SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
Annual Report Pursuant to Section 13 or 15 (d) of
the Securities Exchange Act of 1934
For the fiscal year ended December 31, 1993
Commission File No. 1-9874
CALIFORNIA ENERGY COMPANY, INC.
(Exact name of registrant as specified in its charter)
Delaware 94-2213782
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
10831 Old Mill Road, Omaha, NE 68154
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (402) 330-8900
Securities registered pursuant to Section 12(b) of the Act:
Name of exchange
Title of each class on which registered
Common Stock, $0.0675 New York Stock Exchange
par value ("Common Stock") Pacific Stock Exchange
London Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: N/A
Indicate by check mark whether the Registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the Registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days:
Yes [X] No
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to
this Form 10-K. [X]
Based on the closing sales price of Common Stock on the New York
Stock Exchange on March 21, 1994, the aggregate market value of
the Common Stock held by non-affiliates of the Company was
$614,595,732.
34,382,978 shares of Common Stock were outstanding on
March 21,1994.
DOCUMENTS INCORPORATED BY REFERENCE
Incorporated by reference into this Form 10-K, in response to
Item 3 Part I, Items 6 through 8 of Part II, and Items 10 through
13 of Part III, are the portions indicated herein of (i) the
annual report of California Energy Company, Inc. (the "Company")
to security holders for the fiscal year ended December 31, 1993
(the "Annual Report"), and (ii) the Company's proxy statement
dated for the annual meeting of stockholders to be held on May
12, 1994 (the "Proxy Statement").
TABLE OF CONTENTS
PART I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Item 1. Business . . . . . . . . . . . . . . . . . . . 1
GENERAL . . . . . . . . . . . . . . . . . . . . . . . 1
International Activities . . . . . . . . . . . 2
Geothermal Energy . . . . . . . . . . . . . . . 3
The Independent Power Production Market and
Competition . . . . . . . . . . . . . 3
Business Development Strategies . . . . . . . . 4
THE COSO PROJECT . . . . . . . . . . . . . . . . . . 4
The Coso Geothermal Resource . . . . . . . . . 5
The Coso Facilities . . . . . . . . . . . . . . 6
The Navy I Project . . . . . . . . . . 6
The BLM Project . . . . . . . . . . . 7
The Navy II Project . . . . . . . . . 7
Power Transmission Lines . . . . . . . 7
Management of the Coso Joint Ventures . . . . . 7
Plant Operation and Maintenance
Agreements . . . . . . . . . 8
Field Operation and Maintenance
Agreements . . . . . . . . . 8
Coso Royalty and Other Revenue Sharing
Agreements . . . . . . . . . . . . . . 9
The Navy Contract . . . . . . . . . . 9
Navy I Project . . . . . . . . . . . . 9
Navy II Project . . . . . . . . . . . 9
Termination . . . . . . . . . 10
The BLM Lease . . . . . . . . . . . . 10
Other Revenue Sharing Arrangements . . 11
SO4 Power Sales Agreements . . . . . . . . . . 11
Capacity Payments . . . . . . . . . . 11
Capacity Bonus Payments . . . . . . . 11
Energy Payments . . . . . . . . . . . 12
Non-Recourse Coso Project Financing . . . . . . 13
Security . . . . . . . . . . . . . . . 13
Priority of Payments . . . . . . . . . 14
Conditions to Cash Distributions From the
Coso Joint Ventures . . . . . 14
Required Geothermal Percentage . . . . 14
Debt Service Reserve and Contingency
Funds . . . . . . . . . . . . 14
Support Loans and Project Loan Pledge
Agreements . . . . . . . . . 15
Interest in Caithness Partnerships . . . . . . 15
Coso Joint Venture Notes due to the Company . . 15
OTHER DOMESTIC PROJECTS AND DEVELOPMENT
OPPORTUNITIES . . . . . . . . . . . . . . . . . 15
Desert Peak . . . . . . . . . . . . . . . . . . 15
Roosevelt Hot Springs . . . . . . . . . . . . . 16
Yuma . . . . . . . . . . . . . . . . . . . . . 16
Newberry . . . . . . . . . . . . . . . . . . . 16
Glass Mountain . . . . . . . . . . . . . . . . 17
INTERNATIONAL GEOTHERMAL AND
OTHER DEVELOPMENT OPPORTUNITIES . . . . . . . . . . . 17
International Joint Venture Agreements . . . . 17
Kiewit Joint Venture . . . . . . . . . 18
Distral Joint Venture . . . . . . . . 18
The Philippines . . . . . . . . . . . . . . . . 18
Upper Mahiao . . . . . . . . . . . . . 19
Mahanagdong . . . . . . . . . . . . . 21
Casecnan . . . . . . . . . . . . . . . 21
Indonesia . . . . . . . . . . . . . . . . . . . 22
Dieng . . . . . . . . . . . . . . . . 22
Patuha . . . . . . . . . . . . . . . . 23
REGULATORY AND ENVIRONMENTAL MATTERS . . . . . . . . 23
Environmental Regulation . . . . . . . . . . . 23
Federal Energy Regulations . . . . . . . . . . 24
Permits and Approvals . . . . . . . . . . . . . 24
INSURANCE. . . . . . . . . . . . . . . . . . . . . . 25
EMPLOYEES. . . . . . . . . . . . . . . . . . . . . . 25
Item 2. Properties . . . . . . . . . . . . . . . . . . 25
Item 3. Legal Proceedings. . . . . . . . . . . . . . . 25
Item 4. Submission of Matters to a Vote of Security
Holders. . . . . . . . . . . . . . . . . . . . . . . 25
PART II . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Item 5. Market for Registrant's Common Equity and
Related Stockholder's Matters . . . . . . . . . 26
Item 6. Selected Financial Data . . . . . . . . . . . . 27
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operation. . 27
Item 8. Financial Statements and Supplementary Data . . 27
PART III. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Item 10. Directors and Executive Officers of the
Registrant. . . . . . . . . . . . . . . . . . . 28
Item 11. Executive Compensation. . . . . . . . . . . . . 29
Item 12. Security Ownership of Certain Beneficial
Owners and Management . . . . . . . . . . . . . 29
Item 13. Certain Relationships and Related
Transactions . . . . . . . . . . . . . . . . . 29
PART IV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K . . . . . . . . . . . . . . 30
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
PART I
Item 1. Business
GENERAL
California Energy Company, Inc. (the "Company"), together with
its subsidiaries, is primarily engaged in the exploration for and
development of geothermal resources and the development, ownership
and operation of environmentally responsible independent power
production facilities worldwide utilizing geothermal resources and
other energy sources such as hydroelectric, natural gas, oil and
coal. The Company was an early participant in the domestic
independent power market and is now one of the largest geothermal
power producers in the United States. The Company is also actively
pursuing opportunities in the international independent power
market. The Company is a Delaware corporation which was formed in
1971. The Company's Common Stock is traded on the New York,
Pacific and London Stock Exchanges under the symbol "CE".
Approximately 37% of the Company's Common Stock is owned by a Peter
Kiewit Sons', Inc. subsidiary, Kiewit Energy Company (references
herein to "Kiewit" means Peter Kiewit Sons', Inc. and its
affiliates including Kiewit Energy Company, Kiewit Diversified
Group Inc. and Kiewit Construction Group Inc. or other subsidiaries
thereof, as applicable). Kiewit is a large construction, mining
and telecommunications company headquartered in Omaha, Nebraska.
Kiewit is a joint venture participant in certain of the Company's
international private power projects.
Through its subsidiaries, the Company currently has
substantial ownership interests in, and operates, four geothermal
facilities that are qualified facilities under the Public Utility
Regulatory Policies Act of 1978 ("PURPA"), which requires electric
utilities to purchase electricity from qualified independent power
producers. Three of the Company's geothermal power production
facilities are located at the Naval Air Weapons Station at China
Lake, California (together, the "Coso Project") and are each owned
by separate partnerships (collectively the "Coso Joint Ventures"
and individually the "Navy I Joint Venture", the "BLM Joint
Venture" and the "Navy II Joint Venture"). The Company owns an
interest of approximately 50% in each of the Coso Joint Ventures
and, through a subsidiary, acts as the managing general partner of
each. The Coso Project continues to constitute the Company's
primary source of electrical generation capacity constituting an
aggregate generating capacity of approximately 240 net megawatts
("NMW"). The Coso Project power production facilities have a gross
capacity of approximately 88 megawatts ("MW") each (referred to
individually as the "Navy I Project", the "BLM Project" and the
"Navy II Project"). The Coso Joint Ventures sell all electricity
generated by the Coso Projects pursuant to three long-term "Interim
Standard Offer No. 4" contracts (the "SO4 Agreements") between each
of the Coso Joint Ventures and Southern California Edison Company
("SCE"). These SO4 Agreements provide for energy payments,
capacity payments and capacity bonus payments. The fixed price
periods for energy payments of the SO4 Agreements extend until
August 1997, March 1999 and January 2000 for each of the Navy I
Joint Venture, the BLM Joint Venture and the Navy II Joint Venture,
respectively. Energy payments under the SO4 Agreements have been
fixed at rates ranging from 10.1 cents per kilowatt hour ("kWh") in 1993
to 14.6 cents per Kwh in August 1998. After the fixed price period
expires for each of the Coso Projects, the energy will be purchased
at SCE's then prevailing avoided cost (as determined by the
California Public Utilities Commission) which at present is
substantially lower than the current energy payments under the SO4
Agreement. In addition to the energy payments, SCE makes fixed
annual capacity payments to the Coso Joint Ventures, and under
certain circumstances is required to make capacity bonus payments.
The price for capacity and capacity bonus payments is fixed for the
life of the SO4 Agreements. See "The Coso Project -- SO4 Power
Sales Agreements."
The Company also owns and operates a 10 MW geothermal power
plant located at Desert Peak, Nevada which is a qualified facility
that sells power to Sierra Pacific Power Company, and operates and
owns a 70% interest in a geothermal steam field at Roosevelt Hot
Springs, Utah, which supplies 25 MW of geothermal steam to Utah
Power & Light Company under a 30-year steam sales agreement.
Pursuant to a memorandum of understanding, the Company has
commenced early stage site work on a proposed 30 MW geothermal
project at Newberry, Oregon (the "Newberry Project"), which is
expected to be completed in early 1997 and to be wholly owned and
operated by the Company.
In September 1993, the Company acquired The Ben Holt Co., a 30
person engineering firm located in Pasadena, California which
specializes in the design of geothermal power plants and has
international experience. The Ben Holt Co. will provide support to
the Company's domestic and international projects as well as
continue its services to third parties.
Domestically, the Company plans to focus on developing and
operating geothermal power projects, an area in which the Company
believes it has a competitive advantage due to its geotechnical and
project management expertise and extensive geothermal
leaseholdings. The Company intends to continue to pursue
geothermal opportunities in the Pacific Northwest where it has
extensive geothermal leaseholdings. In March 1993, the Company
acquired 26,000 acres of geothermal leases and three successful
production wells in the Glass Mountain area of Northern California.
In addition, the Company has diversified into other environmentally
responsible sources of power generation. The Company is currently
constructing a 50 NMW natural gas fired cogeneration project in
Yuma, Arizona (the "Yuma Project"), which is expected to be wholly
owned by the Company and to sell electricity to San Diego Gas &
Electric Company ("SDG&E") under a 30-year power sales contract.
The Company anticipates that this project will be completed by mid-
year 1994. See "Other Domestic Projects and Development
Opportunities - Yuma." The Company expects future diversification
through the selective acquisition of partially developed or
existing power generating projects and intends to maintain a
significant equity interest in, and to operate, the projects which
it develops or acquires.
International Activities
The Company presently believes that the international
independent power market holds the majority of new opportunities
for financially attractive private power development in the next
several years. The Company is actively pursuing selected
opportunities in nations where power demand is high and the
Company's geothermal resource development and operating experience,
project development expertise and strategic relationships are
expected to provide it with a competitive advantage. The Company
believes that the opportunities to successfully develop, construct,
finance, own and operate international power projects are
increasing as several countries have initiated the privatization of
the power generation capacity and have solicited bids from foreign
developers to purchase existing generating facilities or to develop
new capacity. Some of these countries, such as the Philippines and
Indonesia, also have extensive geothermal resources.
The Company has recently entered into international joint
venture agreements with Kiewit and Distral S.A. ("Distral"), firms
with significant power plant construction experience, in an effort
to augment and accelerate the Company's capabilities in foreign
energy markets. Joint venture activities with Distral are expected
to be conducted in South America, Central America and the Caribbean
and joint venture activities with Kiewit are expected to be
conducted in Asia, in particular the Philippines and Indonesia, and
in other regions not covered by the Distral joint venture
agreement. See "International Geothermal and Other Development
Opportunities - International Joint Venture Agreements."
The Company has obtained "take-or-pay" power sales contracts
for two geothermal power projects in the Philippines aggregating
approximately 300 MW in capacity. The Upper Mahiao project (the
"Upper Mahiao Project"), a 120 MW geothermal facility with an
estimated total project cost of approximately $226 million, is
expected to be constructed on the island of Leyte and will be over
95% owned and operated by the Company. A syndicate of
international banks is expected to provide approximately $170
million project finance construction loan for the project. The
Company's equity commitment to such project would be approximately
$56 million. The Export-Import Bank of the United States ("ExIm
Bank") is expected to provide the term loan that would be used to
refinance the construction loan for this project, as well as
political risk insurance to the syndicate of commercial banks for
the construction loan. The Company intends to arrange for similar
insurance on its equity investment through the Overseas Private
Investment Corporation ("OPIC") or from other governmental agencies
or commercial sources. The Company expects that both the
construction and the term loan agreements for the Upper Mahiao
Project will be executed in April 1994 and that the notice to
proceed will be issued promptly thereafter under the construction
contract, which was executed in January 1994. Commercial operation
of this project is presently scheduled for mid-year 1996.
The Mahanagdong project (the "Mahanagdong Project"), a 180 MW
geothermal project with an anticipated total project cost of
approximately $310 million, is expected to be operated by the
Company and owned 45% by the Company, 45% by Kiewit and up to 10%
by another industrial company. The Company's equity investment for
the Mahanagdong Project would be approximately $40 million, and the
Company intends to obtain political risk insurance on its
investment similar to that for the Upper Mahiao Project. The
Company is in the process of arranging construction financing for
this project from a syndicate of international banks on terms
similar to those of the Upper Mahiao Project construction loan.
The construction financing is expected to close in mid-year 1994,
with commercial operation presently scheduled for mid-year 1997.
See "International Geothermal and Other Development Opportunities -
The Philippines."
The Company has been awarded the geothermal development rights to
three geothermal fields in Indonesia at Dieng, Patuha and
Lampung/South Sumatra, the initial phases of which could aggregate
an additional generating capacity of 500 NMW. The Company is
currently negotiating power sales contracts for these projects in
Indonesia. See "International Geothermal and Other Development
Opportunities - Indonesia."
Geothermal Energy
Geothermal energy can be economically extracted when water
contained within porous and permeable rock formations comes
sufficiently close to molten rock to heat the water to temperatures
of 400 degrees Fahrenheit or more. The heated water then ascends
towards the surface of the earth, where it can be extracted by
drilling geothermal production wells. The energy necessary to
operate a geothermal power plant is typically obtained from several
such wells, which are drilled using established technology similar
to that employed in the oil and gas industry.
The geothermal production wells are normally located within
approximately one to two miles of a power plant, as geothermal
fluids cannot typically be transported economically over longer
distances. From the well heads, the heated fluid flows through
pipelines to a series of separators, where it is separated into
water "brine" and steam. The steam is passed through a turbine
which drives a generator to generate electricity. Once the steam
has passed through the turbine it is then cooled and condensed back
into water, which along with any brine and noncondensable gases is
returned to the geothermal reservoir via injection wells. The
geothermal reservoir is a renewable source of energy if natural
ground water sources and reinjection of extracted geothermal fluids
are adequate to replenish the geothermal reservoir after the
withdrawal of geothermal fluids. Geothermal plants in the United
States are eligible to be "Qualified Facilities" under PURPA. See
"Regulatory and Environmental Matters"
The Independent Power Production Market and Competition
In the United States, the independent power industry expanded
rapidly in the 1980's, facilitated by the enactment of PURPA.
PURPA was enacted to encourage the production of electricity by
non-utility companies. According to the Utility Data Institute and
the North American Electricity Reliability Council, independent
power producers were responsible for about 50,000 MW, or 43%, of
the U.S. electric generation capacity which has come on line since
1980.
As the size of United States independent power market has
increased, available domestic power capacity and competition in the
industry have also significantly increased. The Company competes
with other independent power producers including affiliates of
utilities, in obtaining long-term contracts to sell electric power
and steam to utilities. In addition, utilities may elect to expand
or create generating capacity through their own direct investments
in new plants. Over the past decade, obtaining a power sales
contract from a U.S. utility has generally become increasingly
difficult, expensive and competitive. Many states now require
power sales contracts to be awarded by competitive bidding, which
both increases the cost of obtaining such contracts and decreases
the chances of obtaining such contracts as bids significantly
outnumber awards in most competitive solicitations. Many of the
Company's competitors have more extensive and more diversified
developmental or operating experience (including international
experience) and greater financial resources than the Company. The
federal Energy Policy Act of 1992 is expected to further increase
domestic competition.
Due to the rapidly growing demand for new power generation
capacity in many foreign countries and resulting privatization of
power development, significant new markets for independent power
generation now exist outside the United States. The Company
intends to take advantage of opportunities in these new markets and
to develop, construct and acquire generation projects outside the
United States. See "International Geothermal and Other Development
Opportunities."
Business Development Strategies
The Company is focusing on market opportunities domestically
in which it believes it has relative competitive advantages, such
as geothermal (because of the Company's geotechnical and project
management expertise and extensive geothermal leaseholdings). In
addition, the Company expects to consider diversification into
other environmentally responsible sources of energy, primarily
through the selected acquisition of partially developed or existing
power generating projects.
The Company is also actively pursuing selected opportunities
abroad in developing nations where power demand is high and the
Company's geothermal operating experience, project development
expertise and strategic relationships with Kiewit and Distral are
expected to provide it with a competitive advantage. The Company
believes that the opportunities to successfully develop, construct
and finance international projects are increasing as several
countries, including the Philippines and Indonesia, have initiated
the privatization of their power generation capacity and have
solicited bids from foreign developers for the purchase of existing
generating capacity or the development of new capacity. In
evaluating and negotiating international projects, the Company
intends to employ a strategy whereby a substantial portion of the
political and financial risks are, through contract provisions or
insurance coverage, borne by parties other than the Company;
however, there can be no assurance that such insurance will be
available on commercially reasonable terms, or that such third
parties will perform such contract provisions.
THE COSO PROJECT
In 1979, the Company entered into a 30-year contract (the
"Navy Contract") with the United States Department of the Navy
("the Navy") to explore for, develop and generate electricity from
geothermal resources located on approximately 5,000 acres of the
Naval Air Weapons Station at China Lake, California. In 1985, the
Company entered into a 30-year lease (the "BLM Lease") with the
United States Bureau of Land Management ("BLM") for approximately
19,000 acres of land adjacent to the land covered by the Navy
Contract. The Company formed the Coso Joint Ventures with one
primary joint venture partner, Caithness Corporation ("Caithness"),
to develop and construct the three facilities which comprise the
Coso Project. The Coso Joint Ventures entered into contracts to
supply electricity to SCE. The contracts were entered into
pursuant to the provisions of PURPA, which, subject to certain
conditions, requires electric utilities to purchase electricity
from qualifying independent power producers.
The three joint ventures which own the Coso Projects are (i)
Coso Finance Partners, which owns the Navy I Project, (ii) Coso
Energy Developers, which owns the BLM Project, and (iii) Coso Power
Developers, which owns the Navy II Project. The Company holds
ownership interests of approximately 46% in the Navy I Joint
Venture; of approximately 48% in the BLM Joint Venture, after
payout to the Company and its joint venture partner; and of 50% in
the Navy II Joint Venture. The remaining portions are owned by
partnerships formed by Caithness and certain investors (the
"Caithness Partnerships"). In addition, the Company indirectly
holds rights to certain cash flows from the Caithness Partnerships
in the BLM Project, and, to a lesser extent, the Navy I Project and
Navy II Project. See "The Coso Project -- Interest in Caithness
Partnerships". Each of the Coso Joint Ventures is managed by a
management committee which consists of two representatives from the
Company and two representatives from the Caithness Partnerships.
The Company also acts as the operator of each of the fields and
plants, for which it receives fees from the Coso Joint Ventures.
The Coso Geothermal Resource
The area in which the Coso Projects are located has been
designated as a "Known Geothermal Resource Area" ("KGRA") by the
United States Department of the Interior, Bureau of Land Management
("BLM") pursuant to the Geothermal Steam Act of 1970. Areas are
designated as KGRAs when the BLM determines that a commercially
viable geothermal resource is likely to exist. There are over 100
other KGRAs in the United States.
The Coso geothermal resource is located in Inyo County,
California, approximately 150 miles northeast of Los Angeles. The
Coso geothermal resource is a liquid-dominated hot water resource
contained within the heterogeneous fractured granitic rocks of the
Coso mountains. It is believed that the heat source for the Coso
geothermal resource is a molten rock or "magma" body located
beneath the field at a depth of six to seven miles. Water in the
system is believed to be supplied from groundwater flow from the
Sierra Nevada mountains located approximately 10 miles west of the
site.
Production is obtained by drilling wells into the fracture
systems, which tap into these reservoirs of hot water. As is
common in this type of geothermal resource, the heterogeneous,
fractured structure makes it somewhat difficult to predict the
performance of new wells even when the new wells are located in
relatively close proximity to existing wells. Geothermal
exploration, development and operations are subject to
uncertainties similar to those typically associated with oil and
gas exploration and development, including dry holes and
uncontrolled well flows. The success of geothermal projects
ultimately depends on the heat content of the extractable fluids,
the geology of the reservoir, the reservoir's actual life, and
operational factors relating to the extraction of the fluids,
including operating expenses, electricity price levels and capital
expenditure requirements. Because of the geological complexities
of geothermal reservoirs, the geographic area and sustainable
output of a geothermal reservoir can only be estimated and cannot
be definitively established. There is, accordingly, a risk of an
unexpected decline in the capacity of geothermal wells, and a risk
of a geothermal reservoir not being sufficient for sustained
generation of the electrical power capacity desired.
Average production of a typical new geothermal production well
is expected by the Coso Joint Ventures to decline 35% to 45% in the
first year, 15% to 25% in the second year, 5% to 15% in the third
year and 5% or less each year thereafter, due to mechanical
deterioration of the well bore, well bore scaling, a decline in
well pressure due to the withdrawal of geothermal fluids, and other
chemical and physical factors. The Coso Joint Ventures have
adopted a program of geothermal well replacement which is intended
to compensate for production decreases.
Production available at the wellhead for the Navy I Project,
the BLM Project and the Navy II Project presently is in excess of
the steam necessary for power production at full capacity for each
plant. Under the loans financing the power plants, each Joint
Venture is required to meet a steam covenant as of May 1st of each
year which requires geothermal reserves of 125% of the resource
required to operate each plant at full capacity.
Management of the Company believes, based on geological and
engineering surveys and analysis of wells drilled, that the Coso
Projects' geothermal resource is sufficient to supply steam to the
Coso Projects of adequate temperature and in sufficient quantities
for the respective terms of the SO4 Agreements. Because of the
uncertainties related to developing, exploring and operating
geothermal resources and the limited history of extracting the
geothermal resource at the sites of the Navy I Project, the BLM
Project and the Navy II Project, there is no assurance that the
geothermal reservoir will continue to supply steam to the Coso
Project at current levels for the remaining terms of the SO4
Agreements.
The Company believes that the facilities producing electricity
at the Coso Project emit significantly less emissions than
electricity production facilities using combustible materials as an
energy source. The geothermal fluids contain certain
noncondensable gases, such as hydrogen sulfide ("H2S"), carbon
dioxide ("C02"), hydrogen, nitrogen, ammonia, methane, and argon,
as well as traces of arsenic (a metal which remains dissolved in
the brine after separation). Certain of the Coso Joint Ventures
hold permits to operate the turbine-generator units which require
that the release of certain noncondensable gases be below specified
levels. The Coso Joint Ventures have, from time to time, exceeded
such levels, particularly with respect to the BLM Project. As a
result, new H2S emissions control systems were installed at the BLM
Project in 1992. H2S emissions control systems are also now under
contract to be installed at the Navy I Project and the Navy II
Project in 1994. Operating permits and California state laws
require that arsenic levels may not exceed specified levels so as
not to endanger worker health and safety. Arsenic comes into
contact with the interior of the pipes and turbine systems and may
be released into sumps during well tests. Failure to construct and
operate the Coso Projects within the applicable regulatory limits
may result in the applicable regulatory agencies levying fines on
the Coso Joint Ventures or curtailing operation of the Coso
Projects until compliance with the regulatory limits is achieved.
The Coso area is subject to frequent low-level seismic
disturbances, and more serious seismic disturbances are possible.
The Coso Project's wells and turbine generator units have been
designed and built to withstand relatively significant seismic
disturbances, but there can be no assurance that they will
withstand any particular disturbance. See "Insurance".
The Coso Facilities
The physical facilities used for geothermal energy production
are substantially the same at the Navy I Project, the BLM Project
and the Navy II Project.
The geothermal fluids produced at the wellhead consist of a
mixture of hot water and steam. The mixture flows from the
wellhead through a gathering system of insulated steel pipelines to
high pressure separation vessels called separators. There, steam
is separated from the water and is sent to a demister in the power
plant, where any remaining water droplets are removed. This
produces a stream of dry steam, which passes through the high
pressure inlet of a turbine generator, producing electricity. The
hot water previously separated from the steam at the high pressure
separators is piped to low pressure separators, where low pressure
steam is separated from the water and sent to the low pressure
inlet of a turbine generator. The hot water remaining after low
pressure steam separation is injected back into the Coso geothermal
resource.
Steam exhausted from the steam turbine is passed to a surface
condenser consisting of an array of tubes through which cold water
circulates. Moisture in the steam leaving the turbine generators
condenses on the tubes and, after being cooled further in a cooling
tower, is used to provide cold circulating water make up for the
condenser.
At the Navy I Project and the Navy II Project, the primary
atmospheric emission control system consists of the surface
condenser, noncondensable gas removal equipment, a gas compressor
unit and the injection wells. The noncondensable gas, which
consists primarily of CO2 with a small percentage of H2S, is
compressed, mixed with the hot water exiting the low pressure
separator and reinjected into the geothermal reservoir. The BLM
Project has the same injection facilities. The Coso Joint Ventures
believe that certain residual, noncondensable gases, primarily CO2
and a small percentage of H2S which were originally being returned
to the geothermal reservoir through the injection wells at the
respective Coso Projects were recycling into the production wells
supplying the Coso Projects, which, together with related equipment
problems, increased H2S emissions and reduced the ability to use
the energy content of the extracted geothermal fluids which in
turn reduced the overall electrical generating capacity for the
Coso Project. Therefore, in addition to the injection wells, a
Dow SulFerox H2S abatement system was installed at the BLM Project
and new LO-CAT II H2S abatement systems are under contract to be
installed at the Navy I Project and Navy II Project in 1994, as
described below.
All of the Coso Projects are designed to operate 24 hours a
day every day of the year. Currently, each year three of the nine
turbine generators are shut down for approximately two weeks for
regular inspection, maintenance and repair. The Company attempts
to schedule these shut-downs during off-peak periods. Weekend
outages are scheduled twice a year for all nine units.
The Navy I Project. The geothermal resource for the Navy I Project
currently is produced from approximately 32 wells located within a
radius of approximately 3,000 feet of the Navy I Project area. The
Navy I Project consists of three individual turbine generators,
each with approximately 32 MW of electrical generating capacity.
The Navy I Project has an aggregate gross electrical generating
capacity of approximately 96 MW, and operated at an average
operating capacity factor of 98.5% in 1991, 99.8% in 1992 and
111.2% in 1993, based on a capacity of 80 NMW.
The Navy I Joint Venture recently executed agreements with ARI
Technologies, Inc. for the Engineering, Procurement and
Construction of a LO-CAT II H2S abatement system and the right to
use that technology. The LO-CAT II H2S abatement system is
expected to be completed in 1994.
The BLM Project. The BLM Project's geothermal resource currently
is produced from approximately 20 wells located within a radius of
approximately 4,000 feet from either the BLM East or BLM West site.
The BLM Project consists of three turbine generators. Two of these
turbine generators are located at the BLM East site in a dual flash
system, each with a nameplate capacity of 29 MW; and one is located
at the BLM West site in a single flash system, with a nameplate
capacity of 29 MW. The BLM Project has an aggregate gross
electrical generating capacity of approximately 96 MW, and operated
at an average operating capacity factor of 71.4% in 1991, 87.2% in
1992, and 98.1% in 1993, based on a capacity of 80 NMW.
The BLM Joint Venture recently completed the construction of
two Dow SulFerox H2S abatement systems for the BLM Project which
have improved the BLM Project's operating efficiency. These H2S
abatement systems were designed by Dow Chemical USA and constructed
by Gilbert Industrial Corp.
The Navy II Project. The geothermal resource for the Navy II
Project currently is produced from approximately 25 wells located
within a radius of approximately 5,000 feet of the Navy II Project
area. The Navy II Project consists of three individual turbine
generators, each with approximately 32 MW of electrical generating
capacity. The Navy II Project has an aggregate gross electrical
capacity of approximately 96 MW, and operated at an average
operating capacity factor of 99.9% in 1991, 98.1% in 1992, and
102.6% in 1993, based on a capacity of 80 NMW.
The Navy II Joint Venture recently executed agreements with
ARI Technologies, Inc. for the Engineering, Procurement and
Construction of a LO-CAT II H2S abatement system and the right to
use that technology. The LO-CAT II H2S abatement system is
expected to be completed in 1994.
Power Transmission Lines. The electricity generated by the Navy I
Project is transmitted over a 28.8 mile 115 kilovolt ("kV")
transmission line to the SCE substation at Inyokern, California.
This transmission line is owned and operated by the Navy I Joint
Venture. The electricity produced by the BLM Project and the Navy
II Project is transmitted on a 230 Kv power line connected to the
SCE substation at Kramer Junction, California (the "Transmission
Line"). Coso Transmission Line Partners, a California general
partnership ("CTLP"), holds title to the Transmission Line and
related facilities, which are used by both the BLM Joint Venture
and the Navy II Joint Venture. The BLM Joint Venture and the Navy
II Joint Venture are the general partners of CTLP. CTLP charges
the BLM Joint Venture and the Navy II Joint Venture for its costs,
allocated in accordance with the proportion of the transmission
capability of the Transmission Line dedicated for each Project's
use. Pursuant to a Transmission Line Operation and Maintenance
Agreement dated as of July 28, 1989 between CTLP and the Company,
the Transmission Line is operated by the Company on behalf of CTLP
for an annual fee.
Management of the Coso Joint Ventures
The managing partner of the Navy I Joint Venture is China Lake
Operating Company ("CLOC"), the managing partner of the BLM Joint
Venture is Coso Hotsprings Intermountain Power, Inc. ("CHIP"), and
the managing partner of the Navy II Joint Venture is Coso
Technology Corporation ("CTC"). CLOC, CHIP and CTC are wholly-
owned subsidiaries of the Company. Each managing partner is
responsible for the conduct of the business of its Joint Venture,
and each has subcontracted with the Company to operate and maintain
its respective plant and geothermal field pursuant to operation and
maintenance agreements as described below. As such, the managing
partners have control over the day-to-day businesses of the Coso
Joint Ventures, including budgeting and development of the Coso
Projects, subject to the oversight of the Management Committee. No
managing partner may be removed without the consent of the Company.
The business operations of each Coso Joint Venture are
overseen by a management committee (each a "Management Committee").
In each case the Management Committee consists of two delegates
appointed by the managing partner and two delegates appointed by
the Caithness Partnerships. Pursuant to the partnership agreement
of each of the Coso Joint Ventures, each Management Committee holds
meetings on a quarterly basis and on such other dates as shall be
called by any of the partners. Action of the Management Committee
may be taken by majority vote of a quorum of at least three
delegates present at a meeting, or by written consent or confirmed
telephonic vote of at least three delegates.
The Management Committee of each of the Coso Joint Ventures
must consent to certain investment and business decisions of the
managing partners, including, without limitation, certain decisions
regarding contracts, engagement of outside consultants, termination
of the Coso Joint Ventures and approval of budgets. For the
purposes of the Coso Project Loans, if the annual budget proposed
by the managing partner is not approved by the Management Committee
in a timely fashion, the managing partner is required to retain an
independent engineering firm to review the proposed budget. If
this proposed budget is approved by the independent engineering
firm as reasonably designed to operate and maintain a facility of
this type and to maximize revenues and net income, the budget as
proposed by the managing partner is deemed to be approved.
Otherwise, any controversies or claims arising out of the
partnership agreements of the Coso Joint Ventures are to be settled
by binding arbitration.
Plant Operation and Maintenance Agreements. By a separate Plant
Operations and Maintenance Agreement ("Plant O&M Agreement") for
each Coso Joint Venture, dated July 15, 1988, in the case of the
Navy I Project, August 3, 1988, in the case of the BLM Project, and
December 30, 1988, in the case of the Navy II Project, the Company
has agreed to perform on behalf of CLOC, CHIP and CTC the operation
and maintenance services for the Coso Projects.
In each case, the Company's performance of these services will
be in accordance with an annual operating budget for each Coso
Project. Pursuant to each Plant O&M Agreement, the Company's
general duties include hiring and training of personnel, testing
and operation of the three turbine generators for each Coso
Project, providing inventories of tools and spare parts, upkeep of
the Transmission Line, furnishing reports required by SCE, the BLM,
the Navy or other governmental authorities, and protecting and
enforcing all warranty rights and claims related to each Coso
Project. Each Coso Joint Venture is a third-party beneficiary of
its respective Plant O&M Agreement.
CLOC, CHIP and CTC compensate the Company for its services
rendered under each Plant O&M Agreement, including reimbursement
for all of the Company's direct costs incurred in operating each
Coso Project, and the operator fees approved by the Coso Joint
Ventures' respective Management Committee. CLOC, CHIP and CTC have
the right to suspend all services performed by the Company under
the respective Plant O&M Agreements under certain circumstances,
including the inability of the Coso Projects or the Transmission
Line to operate for any reason, SCE's refusal or inability to
accept power generated by a Coso Project, or Navy or BLM activities
or restrictions which prohibit economic operation of the Navy I
Project, the BLM Project or the Navy II Project. In the event of
such suspension, CLOC, CHIP and CTC are relieved of their
respective obligations to compensate the Company after 30 days,
after compensating the Company for costs associated with winding
down or resumption of operations.
Each Plant O&M Agreement between CLOC, CHIP or CTC and the
Company may be terminated by the Company upon six months' notice.
Otherwise each Plant O&M Agreement may be terminated in the event
of an uncured default by either party and shall be terminated upon
the termination by SCE of the applicable SO4 Agreement upon the
occurrence of an uncured default thereunder. Under the current
financing arrangements for the Coso Project, the Plant O&M
Agreements have a term equal to the longest maturity of the notes
issued by Coso Funding Corporation and may not be terminated by a
Coso Joint Venture without the consent of the trustee under the
indenture for such notes, and any material amendments or
modifications must be approved by the trustee and an independent
engineering firm.
Field Operation and Maintenance Agreements. The arrangements for
the operation and maintenance of the Navy I, the BLM and the Navy
II geothermal resources are substantially the same as those for the
Navy I, the BLM, and the Navy II plants and facilities, as set
forth above. The obligations of the Company, pursuant to the three
Field Operations and Maintenance Agreements, dated July 15, 1988
for the Navy I Project, August 8, 1988 for the BLM Project, and
December 30, 1988 for the Navy II Project (each a "Field O&M
Agreement"), include performing all testing, permitting and record
keeping services required by the Navy I Joint Venture, the BLM
Joint Venture and the Navy II Joint Venture, the BLM, the Navy or
other government authorities, proper operation and maintenance of
the steam gathering, delivery and injection systems, maintenance of
a qualified staff, and contracting with drilling companies for
repair and replacement of wells. The compensation, suspension,
emergency procedure, third-party beneficiary and termination
provisions of each Field O&M Agreement are substantially the same
as the corresponding provisions in the Plant O&M Agreements, as set
forth above.
Coso Royalty and Other Revenue Sharing Agreements
The receipt of revenues from the Navy I Project, the BLM
Project and the Navy II Project are subject to the following
royalty and other revenue sharing arrangements:
The Navy Contract. In December 1979, the Company entered into the
30-year Navy Contract with the Government of the United States,
acting through the Navy, which granted to the Company exclusive
rights to explore, develop and use the geothermal resource located
within the Naval Air Weapons Station near China Lake, California,
in the Coso KGRA (the "Navy Contract"). The term of the Navy
Contract may be extended for an additional 10 years at the option
of the Navy.
The Navy Contract has been modified on several occasions to
provide for, among other things, assignment of all of the Company's
rights with respect to the Navy I Project and the Navy II Project
to the Navy I Joint Venture and the Navy II Joint Venture,
respectively. In accordance with the terms of the financing
arrangements for the Coso Project, the Navy I and Navy II Joint
Venture's rights and interests pursuant to the Navy Contract have
been assigned as security for the notes issued by Coso Funding
Corporation in connection with the refinancing of existing bank
debt of the Coso Project.
Navy I Project. Under the terms of the Navy Contract, as a royalty
for Unit 1 of the Navy I Project, the Navy I Joint Venture is
obligated to pay for electricity supplied by SCE to the Navy. This
obligation amounted to $9,620,900 in 1993 for 112 million kWh of
electricity. The Navy is obligated to reimburse the Navy I Joint
Venture for the electricity used, at a formula price specified in
the Navy Contract. For 1993, the reimbursement to the Navy I Joint
Venture equaled approximately 71% of the SCE price paid by the Coso
Joint Venture. The percentage reimbursement from the Navy is
escalated semi-annually, not to exceed 95% of the SCE price, in
accordance with a weighted index based on the Consumer Price Index
and price indices for the oil industry, the electric power plant
industry and the construction industry.
In addition, the Navy I Joint Venture is obligated to pay the
Navy the sum of $25.0 million in respect of Unit 1 of the Navy I
Project on December 31, 2009, which is the expiration date of the
initial term of the Navy Contract. This payment will be made from
a sinking fund, to which the Navy I Joint Venture has been making
payments since 1987. Payments to the sinking fund are to be made
at an annual rate of $600,000. As of December 31, 1993,
approximately $2.7 million was on deposit in this sinking fund,
representing both sinking fund payments and accrued interest.
For Units 2 and 3 at the Navy I Project, the Navy I Joint
Venture's royalty expenses are a fixed percentage of its
electricity sales. The royalty expense per Kwh remained constant
at 10.0% through 1993 and will escalate over the life of the Navy
Contract in accordance with the following schedule:
1994-1998. . . . . . . . . . . . . . . . . . . . . . 10.0%
1999-2003. . . . . . . . . . . . . . . . . . . . . . 15.0%
2004-2009. . . . . . . . . . . . . . . . . . . . . . 20.0%
Navy II Project. The Navy II Joint Venture's royalty expenses are
a fixed percentage of its electricity sales. The royalty expense
per Kwh remained constant at 4.0% through 1993 and will escalate
over the life of the Navy Contract in accordance with the following
schedule:
1994 . . . . . . . . . . . . . . . . . . . . . . . . .4.0%
1995-1999. . . . . . . . . . . . . . . . . . . . . . 10.0%
2000-2004. . . . . . . . . . . . . . . . . . . . . . 18.0%
2005-2010. . . . . . . . . . . . . . . . . . . . . . 20.0%
The Navy II Joint Venture is also obligated to pay any
shortfalls in the obligation of the Navy I Joint Venture to make
annual sinking fund payments of $600,000 in respect of the Navy I
Joint Venture's obligation in respect of Unit I of the Navy I
Project to pay the Navy the sum of $25.0 million on December 31,
2009.
Termination. The Navy has the right to terminate the Navy
Contract at any time by giving the Navy I Joint Venture or the Navy
II Joint Venture, or both, as applicable, six months prior written
notice for "reasons of national security, national defense
preparedness, national emergency, or for any reasons the
Contracting Officer shall determine that such termination is in the
best interest of the U.S. Government."
In the event of such termination, the United States Government
is required to pay the Navy I Joint Venture, or the Navy II Joint
Venture, or both, as applicable, for its unamortized exploratory
investment and for its investment in installed power plant
facilities, up to a maximum based on the nameplate capacity of the
turbine generators. With respect to each of the Navy I and Navy II
Joint Ventures, for the first aggregate 25 MW, the maximum is $2.7
million per MW, and for the next 25 MW (i.e. up to 50 MW), the
maximum payment is $2.5 million per MW. For 50-75 MW the maximum
payment is $1.4 million per MW for the Navy I Joint Venture and
$2.3 million per MW for the Navy II Joint Venture. For a total
nameplate capacity of 75 MW for either the Navy I Project or the
Navy II Project, the total maximum payment for termination
compensation would be $165.0 million for the Navy I Joint Venture,
and $187.5 million for the Navy II Joint Venture. The total
aggregate termination compensation for both the Navy I and Navy II
Joint Venture could therefore not exceed $352.5 million. There is
no provision in the contract to compensate either the Navy I or the
Navy II Joint Venture for the loss of anticipated profits resulting
from such termination.
The BLM Lease. On April 29, 1985 the Company and the BLM entered
into an "Offer to Lease and Lease for Geothermal Resources,"
#CA11402 effective as of May 1, 1985 (the "BLM Lease"), pursuant to
which the Company acquired a leasehold interest in approximately
2,500 acres of land, including rights to explore, develop and use
the geothermal resource thereon. All of the Company's rights
pursuant to the BLM Lease have been assigned to the BLM Joint
Venture. The BLM Lease was recorded on May 9, 1988 as Instrument
No. 88-2092 of the Official Records of Inyo County.
The primary term of the BLM Lease is 10 years, however, the
term extends automatically "for so long thereafter as geothermal
steam is produced to be utilized in commercial quantities but shall
in no event continue for more than forty years after the end of the
primary term." Such an automatic extension due to the continuation
of production is termed being "held by production." The BLM Joint
Venture also enjoys a preferential right of renewal of the BLM
Lease for a second forty-year term if the BLM Lease is held by
production at the termination of the forty-year automatic
extension. If the initial 10-year term expired at the present
time, the BLM Lease would be deemed to be "held by production,"
entitling the BLM Joint Venture to an automatic extension.
Royalties to the BLM are 10% of the amount of value of steam
produced, 5.0% of any by-products and 5.0% of commercially
demineralized water. These rates are fixed for the life of the BLM
Lease. Since increased steam production is required to increase
revenues, the royalties based on the value of the steam typically
increase with the revenues. Under the method which has been agreed
to for valuing the steam utilized by the BLM Project, the 10%
royalty translates to an approximate royalty rate of 5.1% on
revenues from electricity sales. The BLM Project does not
currently produce demineralized water, but the sulphur and carbon
dioxide by-products of the Dow SulFerox H2S abatement system are
subject to the BLM royalty schedule. The BLM has the right to
establish minimum production levels after notice and an opportunity
to be heard, and the right to reduce the above royalties if
necessary to encourage the greater recovery of leased resources, or
as otherwise justified.
In addition to the royalties mentioned above, the BLM Joint
Venture is also obligated to pay a royalty to Coso Land Company
("CLC"), an affiliate of the BLM Joint Venture (the "CLC Royalty").
The CLC Royalty is equal to 5.0% of the value of the steam utilized
by the BLM Project, but is subordinated to all other royalties, all
debt service of the BLM Joint Venture and all operating costs of
the BLM Project. The royalty may not be transferred without
consent and is unsecured.
Pursuant to the BLM Lease, the BLM Joint Venture must comply
with certain "Navy Constraints on Naval Weapon Center Lands." These
constraints include, among other things, certain security measures
and restrictions of access, the Navy's right to suspend operations
if an imminent threat to the environment is present, permitting
requirements, information and data exchange, and the Navy's right
of inspection. In addition, BLM leases can be terminated by
operation of law, as follows: (i) at the anniversary date, for
failure to pay the full amount of the annual rental by such date,
and (ii) at the end of the primary term, if there is no production
in commercial quantities, there is no producing well, or actual
drilling operations are not being diligently prosecuted.
Other Revenue Sharing Arrangements. The Company has outstanding
Senior Notes (the "Senior Notes"). The Senior Notes bear interest
at the rate of 12% per annum, plus 10% of the Company's share of
the net cash flow from the Coso Project through December 31, 1994.
SO4 Power Sales Agreements
The Navy I Joint Venture, the BLM Joint Venture and the Navy
II Joint Venture have acquired SO4 Agreements which were originally
executed by SCE and the China Lake Joint Venture ("CLJV"), and by
SCE and Coso Geothermal Company ("CGC"), each of which are
California general partnerships between the Company, Caithness and
others. Under the terms of the SO4 Agreements, the Navy I Joint
Venture, the BLM Joint Venture and the Navy II Joint Venture have
agreed to sell and SCE has agreed to purchase the net electrical
output of the Navy I, the BLM and the Navy II Projects. The SO4
Agreements require that each Coso Project maintain its status as a
qualifying facility under PURPA throughout its respective contract
term.
Pursuant to the SO4 Agreements, SCE must purchase all of the
net electrical output of the Navy I Project until August 2011, of
the BLM Project until March 2019 and of the Navy II Project until
January 2010. In each case, SCE must pay the Navy I Joint Venture,
the BLM Joint Venture and the Navy II Joint Venture capacity
payments, capacity bonus payments and energy payments in accordance
with each Coso Project's output.
Capacity Payments. A Coso Project qualifies for an annual capacity
payment by meeting specified performance requirements on a monthly
basis during an approximately four-month long peak period, which
currently runs during the months of June through September of each
year. The basic performance requirement is that the Coso Project
deliver an average kWh output during specified on-peak hours of
each month in the peak period at a rate equal to at least an 80%
Contract Capacity Factor. The "Contract Capacity Factor" equals
(1) a plant's actual electricity output, measured in kWhs, during
the hours of measurement, divided by (2) the product obtained by
multiplying the plant's "Contract Capacity," as stated in the SO4
Agreement applicable to such plant, by the number of hours in the
measurement period. If a Project maintains the required 80%
Contract Capacity Factor during the applicable periods, the annual
capacity payment will be equal to the product of the capacity
payment per kWh stated in its SO4 Agreement and the Contract
Capacity.
The Navy I Project has a Contract Capacity of 75 MW, and a
capacity payment per kW year of $161.20, for an annual maximum
capacity payment of $12,090,000. The BLM Project and the Navy II
Project each have a Contract Capacity of 67.5 MW, and capacity
payments per kW year of $175.00 and $176.00, respectively, yielding
annual maximum capacity payments of $11,812,500 and $11,880,000,
respectively. Although capacity prices per kWh remain constant
throughout the life of each SO4 Agreement, capacity payments are
disbursed by SCE on a monthly basis in accordance with a tariff
schedule filed with the CPUC. Payments are made unevenly
throughout the year, and are weighted toward the on-peak periods;
currently, approximately 84% of the capacity payments received by
the Coso Joint Ventures from SCE are paid in respect of peak
months, and 16% in respect of non-peak months. As of the end of the
1992 peak season, each of the Coso Projects earned, for the first
time, the maximum capacity and bonus payments available under its
respective SO4 Agreement for the peak months. In 1993 each of the
Coso Projects also earned the maximum capacity and bonus payments
available under its respective SO4 Agreement for the peak and non-
peak months.
Capacity Bonus Payments. Each Coso Joint Venture is entitled to
receive capacity bonus payments during both on-peak and non-peak
months by operating at a Contract Capacity Factor of between 85%
and 100% during on-peak hours of each month. A plant qualifies for
capacity bonus payments in respect of peak months provided that the
plant operates at least at an 85% Contract Capacity Factor during
the on-peak hours of the month, and qualifies in respect of non-
peak months if performance requirements for on-peak months have
been satisfied and the plant also operates at a Contract Capacity
Factor of at least 85% during mid-peak hours of the non-peak month.
Capacity bonus payments for each month increase with the level
of kWhs delivered between the 85% and 100% Contract Capacity Factor
levels during the month. The annual capacity bonus payment for
each month is equal to a percentage based on the plant's on-peak
Contract Capacity Factor (which percentage may not exceed 18% of
one-twelfth of the annual capacity payment).
Energy Payments. In addition to capacity and bonus payments, SCE
must make monthly energy payments to each Coso Joint Venture in
accordance with kWh of energy delivered by each Coso Project. The
energy price component for electricity delivered to SCE is subject
to different pricing mechanisms during the first 10 years of each
SO4 Agreement than are applicable during the remaining term of each
agreement. During the first 10 years following the commencement of
firm power delivery, the energy price per kWh varies between so-
called on-peak and non-peak periods, but the time weighted average
of these prices equals a fixed price per kWh specified in the SO4
Agreements. The stated fixed price in the SO4 Agreements escalates
at an average annual rate of approximately 7.7% per year for the
remainder of the initial 10-year period under the SO4 Agreement for
the Navy I Project, 6.4% per year for the BLM Project and the Navy
II Project. This period ends in August 1997 for the Navy I Joint
Venture, March 1999 for the BLM Joint Venture and January 2000 for
the Navy II Joint Venture. The fixed average energy prices per kWh
which will remain in effect through the year 1998 and which
management of the Coso Joint Ventures believes will be the minimum
amounts payable in 1999 and 2000 are as follows:
Annual %
Year Price/kWh Increase
1993 10.1 cents
1994 10.9 cents 7.9%
1995 11.8 cents 8.3%
1996 12.6 cents 6.8%
1997 13.6 cents 7.9%
1998 14.6 cents 7.4%
1999 14.6 cents 0.0%
2000 14.6 cents 0.0%
After the initial 10-year period under each SO4 Agreement
expires, the energy price paid for electricity delivered under the
agreement will be based upon SCE's short-run avoided cost (as
determined and published from time to time by the CPUC) which at
present is substantially lower than the current energy payments
under the SO4 Agreement. The short-run avoided cost is the product
of its Incremental Energy Rate ("IER") (system efficiency) and its
avoided fuel rate, plus various additions that have been adopted by
the CPUC. The IER and the additions are determined yearly in the
purchasing utility's Energy Cost Adjustment Clause proceeding
before the CPUC. The purchasing utility's avoided fuel and the
corresponding fuel rate are determined monthly by the CPUC. For
the majority of months, the utility's avoided fuel has historically
been gas, although in some winter months the avoided fuel has been
oil. When the avoided fuel is gas, the electric utility's fuel
rate is based on the utility's forecast of its average cost of gas.
When the avoided fuel is oil, the utility's fuel rate is based on
the utility's actual average cost of the most recent period's oil
purchase. Consequently, after the initial 10-year period, energy
payments under the SO4 Agreements will fluctuate based on average
fuel costs in the California energy market.
The Company cannot predict the likely level of avoided cost
energy prices at the expiration of the fixed price period.
Although from time to time, various third parties attempt to
forecast SCE's future avoided costs, the Company believes that all
forecasts of avoided costs are inherently speculative in nature
because SCE's actual avoided costs will be dependent upon, among
other factors, SCE's future fuel costs, system operation
characteristics and regulatory action.
Non-Recourse Coso Project Financing
In December 1992, the Coso Joint Ventures refinanced the
existing bank debt on the Coso Projects with the proceeds of the
sale of approximately $560 million in non-recourse senior secured
notes (the "Notes") in a private placement pursuant to Rule 144A
under the Securities Act of 1933. The Notes were issued by Coso
Funding Corp. ("Coso Funding"), a corporation owned by the Coso
Joint Ventures and formed exclusively for the purpose of issuing
the Notes. Coso Funding has lent the Coso Joint Ventures
substantially all of the net proceeds of the sale of the Notes in
loans known as the "Project Loans".
The Notes were issued in the following amounts, fixed interest
rates and maturities:
Amount Rate Maturity
$ 12,904,000 4.94% December 31, 1992
$ 17,506,000 5.35% June 30, 1993
$ 17,506,000 5.72% December 31, 1993
$ 28,823,000 6.50% June 30, 1994
$ 28,823,000 6.87% December 31, 1994
$ 33,552,000 7.22% June 30, 1995
$ 33,552,000 7.41% December 31, 1995
$167,992,000 7.99% December 31, 1997
$144,504,000 8.53% December 31, 1999
$ 75,083,000 8.87% December 31, 2001
Mandatory semi-annual principal repayments are required with
respect to Notes due 1997, 1999 and 2001 beginning on June 30,
1996, 1998 and 2000, respectively. At the time of their issuance,
the Notes were rated "BBB-" by Standard & Poor's Corporation,
"Baa3" by Moodys Investor's Service Inc., and "BBB" by Duff &
Phelps Credit Rating Co., all investment grade ratings.
The obligations of each Coso Joint Venture under the Project
Loans are non-recourse obligations. Coso Funding may look solely
to each Coso Joint Venture's pledged assets for satisfaction of
such Coso Joint Venture's Project Loan. In addition, the Project
Loans are cross-collateralized by certain support loans ("Support
Loans") only to the extent of the other Coso Joint Ventures'
available cash flow and, under certain circumstances, the debt
service reserve funds, and not as to other assets. The Company is
not liable for the repayment of the Notes or the Project Loans.
Reference is made to the indenture relating to the Notes (the
"Notes Indenture") for a detailed description of the refinancing
terms, including the definition of certain terms used herein.
Security. The Notes are secured by an assignment of Coso Funding's
interest in the Project Loans of the Coso Joint Ventures and a
security interest in all collateral thereunder, as well as by each
Coso Joint Venture's agreement to make payments under certain
circumstances in respect of the other Coso Joint Ventures' Project
Loans, and each Coso Joint Venture's commitment to advance Support
Loans to the other Coso Joint Ventures, as described below.
Security for payment of each Coso Joint Venture's Project Loan
includes: (1) an assignment of all such Coso Joint Venture's
revenues which will be applied against the payment of obligations
of each Coso Joint Venture, including its Project Loan, in
accordance with priorities of payment described below; (2) a
mortgage on the geothermal property interests of each Coso Joint
Venture and the respective Coso Project; (3) a collateral
assignment of certain material contracts; (4) a pledge of the
partnership interests in the Coso Joint Ventures; (5) a pledge of
the stock of all Corporate general partner entities for each Coso
Joint Venture; (6) a debt service reserve fund; (7) a contingency
fund; (8) a pledge of such Coso Joint Venture's capital stock of
Coso Funding; (9) a pledge of such Coso Joint Venture's partnership
interest in CTLP, if any; and (10) any other funds of such Coso
Joint Venture on deposit under the Notes Indenture. The assets
described in clauses (1) through (10) and any other assets securing
a Coso Joint Venture's Project Loan at any time are collectively
referred to herein as the "Collateral." Each Coso Joint Venture's
assets secures only its own Project Loan, and is not cross-
collateralized with the assets pledged under the other Coso Joint
Ventures' Project Loans. However, each Coso Joint Venture is
obligated, to the extent of available cash flow, and under certain
conditions, its debt service reserve fund balance, to make Support
Loans to the other Coso Joint Ventures.
Priority of Payments. Each Coso Joint Venture's revenues are
applied in the following order of priority: (a) royalties due to
the Navy or the BLM; (b) operating and maintenance expenses; (c)
capital expenditures; (d) repayment of working capital lines of
credit of up to $10.0 million; (e) principal and interest payments
on such Coso Joint Venture's Project Loan; (f) Support Loans to the
other Coso Joint Ventures or payments under Project Loan pledge
agreements to maintain an operating capital balance of $1.0 million
and in respect of principal and interest due under the other Coso
Joint Ventures' Project Loans (to the extent described below under
"--Support Loans and Project Loan Pledge Agreements"); (g)
replenishment of any shortfall in such Coso Joint Venture's own
debt service reserve fund; (h) Support Loans to replenish
shortfalls in the other Coso Joint Ventures' debt service reserve
funds; (i) payments in connection with permitted interest rate swap
arrangements; (j) repayment of any outstanding Support Loans; (k)
subordinated royalty payments due to affiliates; (l) other
subordinated obligations, including existing subordinated debt due
to affiliates; and (m) distributions to partners.
Conditions to Cash Distributions From the Coso Joint Ventures. The
terms of the financing restrict the ability of the Coso Joint
Ventures to distribute cash to their partners. In order to
distribute cash, (i) no event of default may exist under the
Project Loans or the Notes, and no notice of such an impending
event of default may have been received from the trustee under the
Notes Indenture, (ii) certain financial ratios must be met, and
(iii) certain thresholds must be met regarding the availability of
an adequate geothermal resource for each of the Coso Projects and
for the Coso Project as a whole, as described in the Notes
Indenture. In addition, the consent of the Management Committee of
each of the Coso Joint Ventures is required for cash distributions.
See "The Coso Project -- Management of the Coso Joint Ventures".
Required Geothermal Percentage. The terms of the financing require
that an independent geothermal engineer prepare a report annually
on the geothermal resource available at the Coso Project as of May
1 of each year. The resource is measured by comparing the
geothermal resource available at the wellhead, or otherwise
available pursuant to contract, with the resource that would be
required to fuel the Coso Projects at their specified capacity
levels of 80 NMW for the Navy I and Navy II Projects and 70 NMW for
the BLM Project. If the geothermal resource for the Coso Project
falls below a set threshold, initially 125% of the resource
required to operate at full capacity, as measured on May 1 of each
year, then the relevant Coso Joint Venture(s) are required to
develop additional steam reserves under a plan of corrective action
approved by the independent geothermal engineer. Depending upon
the results of such efforts, the relevant Coso Joint Venture(s) may
reduce the geothermal resource threshold for permitting cash
distributions by increasing cash reserves available for debt
service. Cash distributions otherwise permitted will be suspended
during any period when the geothermal resources threshold is not
met. On May 1, 1993, the Coso Project met the required steam
reserve covenants.
Debt Service Reserve and Contingency Funds. The debt service
reserve funds for the Coso Joint Ventures are currently fully
funded. With respect to the Navy I Joint Venture, the debt service
reserve requirement requires that the Navy I debt service reserve
fund be equal to at least the next semi-annual principal and
interest payment on the Navy I Joint Venture's Project Loan. With
respect to the BLM Joint Venture and the Navy II Joint Venture, the
debt service reserve requirements will require that the debt
service reserve funds of the BLM Joint Venture and the Navy II
Joint Venture together be equal to at least the aggregate of the
next semi-annual principal and interest payments on the Project
Loans of such Coso Joint Ventures.
In connection with the financing, contingency funds were
funded from the Project Loan to the Navy I Joint Venture to the
extent of approximately $14.0 million, from the Project Loan to the
BLM Joint Venture to the extent of approximately $20.3 million, and
from the Project Loan to the Navy II Joint Venture to the extent of
approximately $34.1 million. The amount of the contingency fund
for each Coso Joint Venture represented the approximate maximum
amount, if any, which could theoretically be payable by such Coso
Joint Venture to third parties to satisfy and discharge all liens
of record and other contract claims encumbering the respective Coso
Projects at the time of the sale of the Notes, including liens and
contract claims which were the subject of litigation between the
Coso Joint Ventures, on the one hand, and Mission Power Engineering
Company ("MPE"), on the other hand, and to establish a reserve for
any other contingencies. The contingency funds were established in
order to obtain ratings to facilitate the offer and sale of the
Notes. The litigation with MPE was settled in June 1993. As a
result of the various payments and releases involved in such
settlement, the Coso Joint Ventures agreed to make a net payment of
$20,000,000 to MPE from the contingency fund and MPE released its
mechanics' liens on the Coso Projects. After paying the settlement
amount to MPE, the remaining balance of the contingency fund
(approximately $49 million) was used to fully fund the Coso
Projects' debt service reserve funds to the maximum of $68 million,
and the remaining $24 million was retained in the contingency fund
for future capital expenditures and debt service according to the
Project Loans.
Support Loans and Project Loan Pledge Agreements. The Support
Loans and the Project Loan pledge agreements have the effect of
cross-collateralizing the Project Loans, but only to a limited
extent. There is no cross-collateralization of the Coso Joint
Ventures' assets.
Subject to certain limitations and conditions, each Coso Joint
Venture has agreed to advance Support Loans to each other Coso
Joint Venture, in the event that the borrowing Joint Venture's
revenues are insufficient to meet scheduled semi-annual principal
and interest payments. The Navy I Joint Venture's obligation to
advance Support Loans is subordinate to the BLM and Navy II Joint
Ventures' obligations to advance Support Loans. In addition, the
debt service reserve fund of the Navy I Joint Venture will be
utilized to fund a Support Loan only to the extent that the amount
in the Navy I Joint Venture debt service reserve fund exceeds the
amount required to defease in full the Navy I Joint Venture's share
of the then outstanding Notes. If a Coso Joint Venture elects to
terminate its Support Loan obligations as permitted under certain
circumstances, it will remain obligated under a Project Loan pledge
agreement to fund principal and interest on the Project Loans of
the other Coso Joint Ventures to the extent of its available cash
flow and, to a limited extent, its debt service reserve fund.
Interest in Caithness Partnerships
In connection with the refinancing of the Coso Projects, the
Company contributed approximately $9.8 million to CEGC-Mojave
Partnership ("CEGC-Mojave"), a recently formed partnership which
used the proceeds to acquire a limited partnership interest in
Caithness CEA Geothermal L.P. ("CCG"), a partnership which is, in
turn, a limited partner in Caithness Coso Holdings, L.P., the
Caithness Partnership which is a partner in the BLM Project. In
addition, certain cash flows of four Caithness affiliates have been
pledged to CEGC-Mojave which relate in part to cash received as a
result of distributions from the Navy I, BLM and Navy II Projects.
Under the terms of the CEGC-Mojave partnership agreement, with
certain exceptions, up to 25% of the cash flows related to the
Caithness affiliates will be distributed to such affiliates, and
the remainder, including all of the cash flows related to the
interest in CCG, will be distributed to the Company until the
Company receives a return of its initial investment plus a 17%
annual rate of return, at which time all distributions revert to
the Caithness affiliates.
Coso Joint Venture Notes due to the Company
In connection with the refinancing of the Coso Project, the
Coso Joint Ventures prepaid a portion of certain notes to the
Company in respect of prior advances made by the Company to the
Coso Project, and amended certain outstanding notes owing to the
Company. As a result the BLM Joint Venture and Navy II Joint
Venture have notes due to the Company in the aggregate amount of
principal and accrued interest of $21,557,996 due March 19, 2002
which bear interest at 12 1/2% annually. The notes are
subordinated to the senior Project Loans on the Coso projects and
interest is not paid currently, but accrues on a pay in kind basis
until final maturity.
OTHER DOMESTIC PROJECTS AND DEVELOPMENT OPPORTUNITIES
Desert Peak
The Company is the owner and operator of a 10 MW geothermal
plant at Desert Peak, Nevada that is currently selling electricity
to Sierra Pacific Power Company under a power sales contract that
expires December 31, 1995 and that may be extended on a year-to-
year basis as agreed by the parties. The price for electricity
under this contract is 6.3 cents per kWh, comprising an energy
payment of 1.8 cents per kWh (which is adjustable pursuant to an
inflation-based index) and a capacity payment of 4.5 cents per kWh.
The Company is currently negotiating the terms of an extension to
this contract.
Roosevelt Hot Springs
The Company operates and owns an approximately 70% interest in
a 25 MW geothermal steam field which supplies geothermal steam to
a power plant owned by Utah Power & Light Company ("UP&L") located
on the Roosevelt Hot Springs property under a 30-year steam sales
contract. The Company obtained approximately $20.3 million of the
cash portion of the purchase price for the properties under a pre-
sale agreement with UP&L whereby UP&L paid in advance the entire
purchase price for the Company's proportionate share of the steam
produced by the steam field. The Company must make certain penalty
payments to UP&L if the steam produced does not meet quantity and
quality requirements.
Yuma
During 1992 the Company acquired a development stage 50 MW
natural gas fired cogeneration project in Yuma, Arizona. The Yuma
Project is designed to be a qualified facility under PURPA and to
provide 50 NMW of electricity to SDG&E over an existing 30 year
power purchase contract. The electricity is to be sold at SDG&E's
avoided cost. The power will be wheeled to SDG&E over transmission
lines constructed and owned by Arizona Public Service Company
("APS"). An Agreement for Interconnection and a Firm Transmission
Service Agreement have been executed between APS and the Yuma
Project entity and have been accepted for filing by the Federal
Energy Regulatory Commission ("FERC").
The Power Sales Agreement with SDG&E requires the Yuma Project
to commence reliable operations by December 31, 1994. The Company
currently anticipates that construction will be completed and
reliable operations will commence by mid-1994. The project entity
has executed steam sales contracts with an adjacent industrial
entity to act as its thermal host in order to maintain its status
as a qualified facility, which is a requirement of its SDG&E
contract. Since the industrial entity has the right under its
contract to terminate the agreement upon one year's notice if a
change in its technology eliminates its need for steam, and in any
case to terminate the agreement at any time upon three years
notice, there can be no assurance that the Yuma Project will
maintain its status as a qualified facility. However, if the
industrial entity terminates the agreement, the Company anticipates
that it will be able to locate an alternative thermal host in order
to maintain its status as a qualified facility or build a
greenhouse at the site for which the Company believes it would
obtain qualified facility status. A natural gas supply and
transportation agreement has been executed with Southwest Gas
Corporation.
The Yuma Project is being constructed pursuant to a fixed
price turnkey contract with Raytheon Engineers & Constructors for
approximately $43 million, of which the Company has to date funded
approximately $39 million from internal sources. The Company
currently intends to fund the balance from internal sources as
construction expenditures are incurred.
Newberry
Under a Bonneville Power Administration ("BPA") geothermal
pilot program, the Company is developing a 30 NMW geothermal
project at Newberry, Oregon (the "Newberry Project"). Pursuant to
a Memorandum of Understanding executed in January 1993, the Company
has agreed to sell 20 NMW of Power to BPA and 10 NMW to Eugene
Water and Electric Board ("EWEB") from the Newberry Project. In
addition, BPA has an option to purchase up to an additional 100 MW
of production from the project under certain circumstances. In a
public-private development effort, the Company is responsible for
development, permitting, financing, construction and operation of
the project (which will be 100% owned by the Company), while EWEB
will cooperate in the development efforts by providing assistance
with government and community affairs and sharing in the
development costs (up to 30%). The Newberry Project is currently
expected to commence commercial operation in 1997. The memorandum
of understanding provides that under certain circumstances the
contracts may be utilized at an alternative location.
A draft environmental impact study with respect to the
Newberry Project was completed in January 1994 and is expected to
be finalized in mid-year 1994, at which time the Company expects to
commence drilling of the geothermal wells and to execute the power
sales contracts, subject to obtaining all governmental permits and
approvals.
Glass Mountain
In March 1993, the Company completed the acquisition of an
approximate 65% interest in 26,000 acres of geothermal leaseholds
at Glass Mountain in Northern California, which include three
successful production wells with an existing capacity of between 15
to 30 MW. The Company believes that this acreage represents one of
the finest undeveloped geothermal reservoirs in the country. The
Company has attempted to negotiate the terms of a power sales
contract to exploit this geothermal resource; however, no agreement
exists to date.
INTERNATIONAL GEOTHERMAL AND
OTHER DEVELOPMENT OPPORTUNITIES
The Company presently believes that the international
independent power market holds the majority of new opportunities
for financially attractive private power development in the next
several years, because the demand for new generating capacity is
growing more rapidly in foreign markets, especially emerging
nations, than in the United States. The World Bank estimates that
developing countries will need approximately 380,000 MW of new
generating capacity over the next decade. The need for such rapid
expansion has forced many countries to select private power
development as their only practical alternative and to restructure
their legislative and regulatory schemes to facilitate such
development. The Company believes that this significant need for
power has created strong local support for private power projects
in many foreign countries and increased the availability of long-
term multilateral lending agency and foreign source financing and
political risk insurance for certain international private power
projects, particularly those utilizing indigenous fuel sources and
renewable or otherwise environmentally responsible generating
facilities. The Company intends to focus its international efforts
on the development, construction, ownership and operation of such
projects.
In developing its international strategy, the Company intends
to pursue development opportunities in countries which it believes
have an acceptable risk profile and where the Company's geothermal
resource development and operating experience, project development
expertise or strategic relationship with Kiewit or local partners
are expected to provide it with a competitive advantage. The
Company is currently pursuing a number of electric power project
opportunities in countries such as the Philippines and Indonesia,
which have initiated private power programs and have extensive
geothermal resources. The Company's development efforts include
both so-called "green field" development, in which the Company
attempts to negotiate unsolicited power sales contracts for new
generation capacity or engages in competitive bids in response to
government agency or utility requests for proposals for new
capacity, as well as the acquisition of or participation in the
joint development of projects which are under development or
already operating. To better position itself to pursue
international project development opportunities in the Asian
market, the Company recently established an office in Singapore to
oversee its activities in that region, including the Philippines
and Indonesia. In pursuing international projects, the Company
intends to maintain a significant equity interest in, and to
operate, the projects that it develops or acquires.
In order to compete more effectively internationally, the
Company's strategy is to diversify its project portfolio, reduce
its future equity commitments and leverage its capabilities in
international projects by developing most international projects on
a joint venture basis. To that end, the Company has recently
entered into international joint venture agreements with Kiewit and
Distral (firms with extensive power plant construction experience)
in a effort to augment and accelerate the Company's capabilities in
foreign energy markets. Joint venture activities with Distral are
expected to be conducted in South America, Central America and the
Caribbean and joint venture activities with Kiewit are expected to
be conducted in Asia (in particular the Philippines and Indonesia)
and in other regions not covered by the Distral joint venture
agreement. See "- International Joint Venture Agreements."
International Joint Venture Agreements
As part of the Company's international development strategy,
the Company recently signed separate joint venture agreements with
Kiewit and Distral. These joint ventures provide the Company with
strategic alliances with firms possessing unique private power and
construction expertise. The Company believes these strategic joint
venture relationships will augment and accelerate its development
capabilities in foreign energy markets and provide it with a
relative competitive advantage. In addition, the Company believes
that participation in these joint ventures will help the Company
diversify its project risk profile, leverage its development
capabilities and reduce future requirements to raise additional
equity for projects. The Company also believes that it is
important in foreign transactions to establish strong relationships
with local partners (such as Distral in Central and South America
and P.T. Himpurna and P.T. ESA (each as defined below) in
Indonesia) who are knowledgeable of local cultural, political and
commercial practices and who provide a visible local presence and
local project representation.
Kiewit Joint Venture. On December 14, 1993, the Company signed a
joint venture agreement with Kiewit affiliates (Kiewit Diversified
Group Inc. and Kiewit Construction Group Inc.). Kiewit is one of
the largest construction companies in North America and has been in
the construction business since 1884. Kiewit is a diversified
industrial company with approximately $2.0 billion in revenues in
1993 from operations in construction, mining and
telecommunications. Kiewit has built a number of power plants in
the United States and large infrastructure projects and industrial
facilities worldwide, and owns approximately 37% beneficial
interest in the Company.
The Kiewit joint venture agreement, which has an initial term
of three years, provides each party a right of first refusal to
pursue jointly all "build, own and operate" or "build, own, operate
and transfer" power projects identified by the other party or its
affiliates outside of the United States, except in locations
covered by the Distral joint venture agreement described below.
The Kiewit joint venture agreement provides that, if both parties
agree to participate in a project, they will share all development
costs equally, each of the Company and Kiewit will provide 50% of
the equity required for financing a project developed by the joint
venture and the Company will operate and manage any such project.
The agreement contemplates a joint development structure under
which, on a project by project basis, the Company will be the
development manager, managing partner and/or project operator, an
equal equity participant with Kiewit and a preferred participant in
the construction consortium, and Kiewit will be an equal equity
participant and the preferred turnkey construction contractor, with
the construction consortium providing customary security to project
lenders (including the Company) for liquidated damages and
completion guarantees. The joint venture agreement may be
terminated by either party on 15 days written notice, provided that
such termination cannot affect the pre-existing contractual
obligations of either party.
Distral Joint Venture. On December 14, 1993, the Company entered
into a joint venture agreement with Distral of the Lancaster
Distral Group. Distral is a South American turnkey construction
contractor and manufacturer of boilers, generators and heavy
equipment, and has constructed, engineered or supplied equipment to
numerous coal, gas and hydroelectric power plants located in
Central and South America. The Company believes that, in addition
to its extensive experience in energy-related business, Distral
brings substantial knowledge of the customs and commercial
practices in Central and South America, as well as knowledge of the
general power markets and specific power project opportunities in
such regions.
The joint venture agreement, which has an initial term of
three years, provides that the joint venture will have the right of
first refusal to jointly pursue all power projects identified by
the joint venture, the Company, Distral or their affiliates (other
than Kiewit) in the Caribbean, South America and that part of
Central America south of Mexico. The agreement provides that the
Company and Distral will share all development costs equally, if
both parties agree to participate in a project. The Company is
required to provide at least 50% of the equity required to finance
any project developed by the joint venture; provided, however, that
the Company may assign up to 50% of its equity interest in any such
project to Kiewit and its affiliates. The agreement contemplates
a joint development structure under which the Company and Distral
will jointly operate and maintain each joint venture project, with
the Company responsible for overall supervision and management.
The Distral agreement may be terminated at any time by the Company
or Distral, provided that such termination cannot affect the pre-
existing contractual obligations of either party.
The Philippines
The Company believes that increasing industrialization, a
rising standard of living and an expanding power distribution
network has significantly increased demand for electrical power in
the Philippines. Currently, according to the 1993 Power
Development Program of the National Power Corporation of the
Philippines ("NAPOCOR"), demand for electricity exceeds supply.
NAPOCOR has also reported that its ability to sustain current
levels of electric production from existing facilities has been
limited due to frequent breakdowns in many of its older electric
generating plants and an extended drought, which has limited
hydroelectric generation. As a result, the Philippines has
experienced severe power outages, with Manila suffering significant
daily brownouts during much of 1993. Although the occurrence of
brownouts has been recently reduced, NAPOCOR has said that it still
anticipates significant energy shortages in the future.
In 1993, the Philippine Congress, pursuant to Republic Act
7648, granted President Ramos emergency powers to remedy the
Philippines' energy crisis, including authority to (i) exempt power
projects from public bidding requirements, (ii) increase power
rates and (iii) reorganize NAPOCOR. Until 1987, NAPOCOR had a
monopoly on power generation and transmission in the Philippines.
In 1987, then President Aquino issued Executive Order No. 215,
which grants private companies the right to develop certain power
generation projects, such as those using indigenous energy sources
on a "build-operate-transfer" or "build-transfer" basis. In 1990,
the Philippine Congress enacted Republic Act No. 6957, which
authorizes private development of priority infra-structure projects
on a "build-operate-transfer" and a "build-transfer" basis. In
addition, under that Act, such power projects are eligible for
certain tax benefits, including exemption from Philippine national
income taxes for at least six years and exemption from, or
reimbursement for, customs duties and value added taxes on capital
equipment to be incorporated into such projects.
In a effort to remedy the shortfall of electricity, the
Republic of the Philippines, NAPOCOR and the Philippine National
Oil Company-Energy Development Company ("PNOC-EDC") are jointly
soliciting bids for private power projects. The potential
Philippine indigenous resources include geothermal, hydro and coal,
of which geothermal power has been identified as a preferred
alternative. The Philippine Government has elected to promote
geothermal power development due to the domestic availability and
the minimal environmental effects of geothermal power in comparison
to other forms of power production. PNOC-EDC, which is responsible
for developing the Philippines' domestic energy sources, has been
successful in the exploration and development of geothermal
resources.
The Company has been awarded and signed power contracts with
PNOC-EDC for two geothermal projects, Upper Mahiao and Mahanagdong,
aggregating 300 MW. The following is a summary description of
certain information concerning these and other projects as it is
currently known to the Company. Since these projects are still in
development, however, there can be no assurance that this
information will not change over time. In addition, there can be
no assurance that development efforts on any particular project, or
the Company's efforts generally, will be successful.
Upper Mahiao. The Company is negotiating the final terms of the
construction and term project financing for a 120 MW geothermal
project to be located in the Greater Tongonan area of the island of
Leyte, Republic of the Philippines (the "Upper Mahiao Project").
The Upper Mahiao Project will be built, owned and operated by CE
Cebu Geothermal Power Company, Inc. ("CE Cebu"), a Philippine
corporation that will be more than 95% indirectly owned by the
Company. It will sell 100% of its capacity on a "take-or-pay"
basis (described below) to PNOC-EDC, which will in turn sell the
power to NAPOCOR for distribution to the island of Cebu, located
about 40 miles west of Leyte.
The Company estimates that Upper Mahiao will have a total
project cost of approximately $226 million, including interest
during construction, project contingency costs and a debt service
reserve fund. A consortium of international banks is expected to
provide an approximately $170 million project-financed construction
loan, supported by political risk insurance from the Export-Import
Bank of the United States ("ExIm Bank"). The Company expects that
the term loan for the project will also be provided by the ExIm
Bank, and that both the construction and the term loan agreements
will be executed in April 1994. Shortly thereafter, the Company
expects to issue a notice to proceed to the Contractor under the
Mahiao EPC Contract (as defined below), with commercial operations
scheduled for mid-year 1996. The Company expects that its equity
commitment to the Upper Mahiao Project will be about $56 million.
The Company intends to arrange for political risk insurance on this
equity investment through OPIC or from governmental agencies or
commercial sources.
The Upper Mahiao Project will be constructed by Ormat, Inc.
("Ormat") and its affiliates pursuant to supply and construction
contracts (collectively the "Mahiao EPC Contract"), which, taken
together, provide for the construction of the plant on a fixed-
price, date-certain, turnkey basis. Ormat is an international
manufacturer and construction contractor that builds binary
geothermal turbines; it has provided its equipment to several
geothermal power projects throughout the United States and
internationally. The Mahiao EPC Contract provides liquidated
damage protection of 30% of the Mahiao EPC Contract price. Ormat's
performance under the Mahiao EPC Contract will be backed by a
completion guaranty of Ormat, by letters of credit, and by a
guaranty of Ormat Industries, Ltd., an Israeli corporation and the
parent of Ormat, in each case for the benefit of, and satisfactory
to, the project lenders.
Under the terms of the Energy Conversion Agreement, executed
on September 6, 1993 (the "Upper Mahiao ECA"), CE Cebu will build,
own and operate the Project during the two-year construction period
and the ten year cooperation period, after which ownership will be
transferred to PNOC-EDC at no cost. The effectiveness of the Upper
Mahiao ECA is subject to the satisfaction or waiver of certain
conditions prior to April 8, 1994 (subject to extension by
agreement of the parties) including finalization of the principal
project documents (including a power purchase agreement between
PNOC-EDC and NAPOCOR), posting by Ormat of a construction
performance bond in favor of PNOC-EDC in the amount of
approximately $11.8 million, obtaining permits and approvals from
various Philippine governmental authorities and arranging financing
commitments. In the event the parties are unable to satisfy such
conditions before the agreed upon effectivity date, either party
may terminate the Upper Mahiao ECA and such party shall reimburse
the other party for its costs and expenses incurred in connection
with such agreement.
The Upper Mahiao Project will be located on land to be
provided by PNOC-EDC at no cost; it will take geothermal steam and
fluid, also provided by PNOC-EDC at no cost, and convert its
thermal energy into electrical energy to be sold to PNOC-EDC on a
"take-or-pay" basis. Specifically, PNOC-EDC will be obligated to
pay for the electric capacity that is nominated each year by CE
Cebu, irrespective of whether PNOC-EDC is willing or able to accept
delivery of such capacity. PNOC-EDC will pay to CE Cebu a fee (the
"Capacity Fee") based on the plant capacity nominated to PNOC-EDC
in any year (which, at the plant's design capacity is approximately
95% of total contract revenues) and a fee ( the "Energy Fee") based
on the electricity actually delivered to PNOC-EDC (approximately 5%
of total contract revenues). The Capacity Fee consists of three
separate components: a fee to recover the capital costs of the
project, a fee to recover fixed operating costs and a fee to cover
return on investment. The Energy Fee is designed to cover all
variable operating and maintenance costs of the power plant.
Payments under the Upper Mahiao ECA will be denominated in U.S.
dollars, or computed in dollars and paid in Philippine pesos at the
then-current exchange rate, except for the Energy Fee, which will
be used to pay peso-denominated expenses. The ECA provides a
mechanism to convert Philippine pesos to dollars. Significant
portions of the Capacity Fee and Energy Fee will be indexed to U.S.
and Philippine inflation rates, respectively. PNOC-EDC's "take-or-
pay" performance requirement, and its other obligations under the
Upper Mahiao ECA, are guaranteed by the Republic of the Philippines
through a performance undertaking.
The payment of Capacity Fees is not excused if PNOC-EDC fails
to deliver or remove the steam or fluids or fails to provide the
transmission facilities, even if its failure was caused by a force
majeure event. In addition, PNOC-EDC must continue to make
Capacity Fee Payments if there is a force majeure event (e.g. war,
nationalization, etc.) that affects the operation of the Upper
Mahiao Project and that is within the reasonable control of PNOC-
EDC or the government of the Republic of the Philippines or any
agency or authority thereof. If CE Cebu fails to meet certain
construction milestones or the power plant fails to achieve 70% of
its design capacity by the date that is 120 days after the
scheduled completion date (as that date may be extended for force
majeure and other reasons under the Upper Mahiao ECA), the Upper
Mahiao Project may, under certain circumstances, be deemed
"abandoned," in which case the Upper Mahiao Project must be
transferred to PNOC-EDC at no cost, subject to any liens existing
thereon.
PNOC-EDC is obligated to purchase CE Cebu's interest in the
facility under certain circumstances, including (i) extended
outages resulting from the failure of PNOC-EDC to provide the
required geothermal fluid, (ii) changes in tax, environmental or
other laws which would materially adversely affect CE Cebu's
interest in the project, (iii) transmission failure, (iv) failure
of PNOC-EDC to make timely payments of amounts due under the Upper
Mahiao ECA, (v) privatization of PNOC-EDC or NAPOCOR, and (vi)
certain other events. Prior to completion of the Upper Mahiao
Project, the buy-out price will be equal to all costs incurred
through the date of the buy-out, including all Upper Mahiao Project
debt, plus an additional rate of return on equity of ten percent
per annum. In a post-completion buy-out, the price will be the net
present value at a ten percent discount rate of the total remaining
amount of Capacity Fees over the remaining term of the Upper Mahiao
ECA.
Mahanagdong. The Mahanagdong Project is expected to be a 180 MW
geothermal project, which will also be located on the island of
Leyte. The Mahanagdong Project will be built, owned and operated
by CE Luzon Geothermal Power Company, Inc. ("CE Luzon"), a
Philippine corporation that is currently expected to be indirectly
owned as follows: 45% by the Company, 45% by Kiewit and up to 10%
by another industrial company. It will sell 100% of its capacity
on a take-or-pay basis (as described above for the Upper Mahiao
Project) to PNOC-EDC, which will in turn sell the power to NAPOCOR
for distribution to the island of Luzon.
The Company estimates that Mahanagdong will have a total
project cost of approximately $310 million, including interest
during construction, project contingency costs and a debt service
reserve fund. The proposed capital structure is 75% debt, with a
construction and term loan of approximately $225 million and 25%
equity, or approximately $85 million in equity contributions. The
Company believes that political risk insurance from ExIm Bank for
financing of the procurement of U.S. goods and services is
available and, if appropriate, will request similar coverage from
the Export-Import Bank of Japan for Japanese goods and services.
The Company is in the process of arranging construction financing
for the Mahanagdong Project from a consortium of international
banks. Construction of the Mahanagdong Project is expected to
commence in mid-year 1994, with commercial operation presently
scheduled for mid-year 1997. The Company's equity investment for
the Mahanagdong Project is expected to be about $40 million, and
the Company expects to arrange for political risk insurance on this
equity investment through OPIC or from governmental agencies or
commercial sources.
The Mahanagdong Project will be constructed by a consortium of
Kiewit Construction Group, Inc. ("KCG") and The Ben Holt Co.
("BHCO") (the "EPC Consortium"), pursuant to fixed-price, date-
certain, turnkey supply and construction contracts (collectively
the "Mahanagdong EPC Contract"). The obligations of the EPC
Consortium under the Mahanagdong EPC Contract will be supported by
letters of credit, bonds, guarantees or other acceptable security
in an aggregate amount equal to approximately 30% of the
Mahanagdong EPC Contract's price, plus a joint and several guaranty
of each of the EPC Consortium members. KCG, a wholly-owned
subsidiary of Kiewit, will be the lead member of the EPC
Consortium, with an 80% interest. KCG performs construction
services for a wide range of public and private customers in the
U.S. and internationally. Construction projects undertaken by KCG
during 1992 included: transportation projects, including highways,
bridges, airports and railroads; power facilities; buildings and
sewer and waste disposal systems; with the balance consisting of
water supply systems, utility facilities, dams and reservoirs. KCG
accounted for 80% of Kiewit's revenues, contributing $1.7 billion
in revenues in 1993. KCG has an extensive background in power
plant construction.
BHCO will provide design and engineering services for the EPC
Consortium, holding a 20% interest. BHCO, wholly-owned by the
Company, is a California based engineering firm with over 25 years
of geothermal experience, specializing in feasibility studies,
process design, detailed engineering, procurement, construction and
operation of geothermal power plants, gathering systems and related
facilities. The Company will provide a guaranty of BHCO's
obligations under the Mahanagdong EPC Contract.
The terms of the Energy Conversion Agreement (the "Mahanagdong
ECA"), executed on September 18, 1993, are substantially similar to
those in the Upper Mahiao ECA. The Mahanagdong ECA provides for a
three-year construction period, and its effectivity deadline date
is in July 1994. All of PNOC-EDC's obligations under the
Mahanagdong ECA will be guaranteed by the Republic of the
Philippines through a performance undertaking. The Capacity Fees
are expected to be approximately 97% of total revenues at the
expected capacity levels and the Energy Fees are expected to be
approximately 3% of such total revenues.
Casecnan. The Company has been granted exclusive rights to
negotiate an energy sales contract with NAPOCOR and a water sales
contract with the National Philippine Irrigation Administration in
connection with a proposed 60 MW hydro-electric generating facility
to be located in the Casecnan area on the island of Luzon. These
contracts will be structured as take-or-pay capacity and energy
agreements, with capacity payments representing the bulk of the
revenues. Negotiations have only recently commenced on this
potential project, and there can be no assurance at this time that
any agreement will be reached by the parties.
Indonesia
The Republic of Indonesia is experiencing demand for
electrical power that exceeds current supply, and has a number of
promising geothermal reservoirs. Recent Indonesian legislation has
facilitated foreign ownership and operation of private electrical
power generation and transmission facilities. The Company's
subsidiaries are currently negotiating several potential project
agreements for geothermal power facilities in Indonesia.
The following is a summary description of certain information
concerning these projects as it is currently known to the Company.
Since those projects are still in development, however, there can
be no assurance that this information will not change materially
over time. In addition, there can be no assurance that development
efforts on any particular project, or the Company's efforts
generally, will be successful.
Dieng. Through memoranda of understanding executed by Perusahaan
Pertambangan Minyak Dan Gas Bumi Negara ("Pertamina"), the
Indonesian national oil company, and assigned to the Company, the
Company has been awarded the exclusive right to develop geothermal
resources in the Dieng region of central Java, Indonesia (the
"Dieng Project"). A subsidiary of the Company has entered into a
Joint Development Agreement with P.T. Himpurna Enersindo Abadi
("P.T. HEA"), its Indonesian partner, which is a subsidiary of
Himpurna, an association of Indonesian military veterans, whereby
the Company and P.T. HEA have agreed to work together on an
exclusive basis to develop the Dieng Project (the "Dieng JV"). The
Dieng JV is expected to be structured such that subsidiaries of the
Company will have a 45% interest, subsidiaries of Kiewit will have
the option to take a 45% interest and P.T. HEA will have a 10%
interest in the Dieng Project. The Dieng JV expects to conduct
geothermal exploration and development in the Dieng field, to
build, own and operate power generating facilities and to sell the
power generated to Perusahaan Umum Listrik Negara ("PLN"), the
Indonesian national electric utility.
The Dieng JV and Pertamina are currently negotiating a
proposed Joint Operation Contract (the "Dieng JOC") pursuant to
which Pertamina would contribute the geothermal field and the wells
and other facilities presently located thereon and the Dieng JV
initially would build, own and operate four power production units
comprising an aggregate of 220 MW. The Dieng JV will accept the
field operation responsibility for developing and supplying the
geothermal steam and fluids required to operate the plants. The
current proposed Dieng JOC would expire (subject to extension by
mutual agreement) on the date which is the later of (i) 42 years
following completion of well testing and (ii) 30 years following
the date of commencement of commercial operation of the final unit
completed. Upon the expiration of the proposed Dieng JOC, all
facilities would be transferred to Pertamina at no cost. Under the
proposed Dieng JOC, the Dieng JV would be required to pay Pertamina
a production allowance equal to three percent of the Dieng JV's net
operating income from the Dieng Project, plus a further percentage
based upon the negotiated value of existing Pertamina geothermal
production facilities that the Company expects will be contributed
by Pertamina.
The Dieng JV and Pertamina are currently negotiating a
proposed "take-or-pay" Energy Sales Contract (the "Dieng ESC") with
PLN whereby PLN would agree to purchase and pay for all electricity
delivered or capacity made available from the Dieng Project for a
term equal to that of the Dieng JOC. Under the current draft, the
price paid for electricity would equal a base energy price per kWh
multiplied by the number of kWh the plants deliver or are "capable
of delivering," whichever is greater. Electricity revenue payments
would also be adjusted for inflation and fluctuations in exchange
rates.
Assuming execution of the Dieng JOC and the Dieng ESC, the
Company presently intends to begin well testing by the second
quarter of 1994 and to commence construction of an initial 55 MW
unit in the fourth quarter of 1994, and then to proceed on a
modular basis with construction of three additional units to follow
shortly thereafter, resulting in an aggregate first phase at this
site of 220 MW. The Company estimates that the total project cost
of these units will be approximately $450 million. The Company
anticipates that the Dieng Project will be designed and constructed
by a consortium consisting of KCG and BHCO, and that the Company
(through a subsidiary) will be responsible for operating and
managing the Dieng Project.
The Dieng field has been explored domestically for over 20
years and BHCO has been active in the area for more than five
years. The Company has a significant amount of data, which it
believes to be reliable as to the production capacity of the field.
However, a number of significant steps, both financial and
operational, must be completed before the Dieng Project can
proceed. These steps, none of which can be assured, include
obtaining required regulatory permits and approvals, entering into
the Dieng JOC, undertaking and completing the well testing
contemplated by the Dieng JOC, entering into the Dieng ESC, the
construction agreement and other project contracts, and arranging
financing.
Patuha. The Company has also negotiated a memorandum of
understanding and expects to execute a definitive agreement with
Pertamina for the exclusive geothermal development rights with
respect to the Patuha geothermal field in Java, Indonesia (the
"Patuha Project"). The Company has entered into an agreement to
establish a joint venture for Patuha with P.T. Enerindo Supra
Abadi, an Indonesian company ("P.T. ESA") (the "Patuha JV"). P.T.
ESA is an affiliate of the Bukaka Group, which has extensive
experience in general construction, fabrication and electrical
transmission construction in Indonesia. In exchange for project
development services, P.T. ESA is expected to receive a 10% equity
interest in the Patuha Project with an option to acquire an
additional 20% interest for cash upon the satisfaction of certain
conditions. Subject to the exercise of that option, subsidiaries
of the Company will have a 45% interest and subsidiaries of Kiewit
will have the option to take a 45% interest in the Patuha Project.
The Patuha JV is currently negotiating both a Joint Operation
Contract ("JOC") and an Energy Sales Contract ("ESC"), each of
which currently contains terms substantially similar to those
described above for the Dieng Project. The Patuha JV presently
intends to proceed on a modular basis like the Dieng Project, with
an initial 55 MW unit to be built followed by three additional
units, in total aggregating 220 MW. The Company estimates that the
total cost of these four units will be approximately $450 million.
Assuming execution of both a JOC and an ESC, field development is
expected to commence in the first quarter of 1995 with construction
of the first unit expected to begin by mid-year 1996.
The Patuha Project remains subject to a number of significant
uncertainties, as described above in connection with the Dieng
Project, and there can be no assurance that the Patuha Project will
proceed or reach commercial operation.
Lampung/South Sumatra. The Company and P.T. ESA have also formed
a joint venture (the "Lampung JV") to pursue development of
geothermal resources in the Lampung/South Sumatra regions (the
"Lampung Project"). The Lampung JV is presently exploring several
geothermal fields in this region and is negotiating a memorandum of
understanding for a JOC and ESC for these prospects containing
terms substantially similar to those described above for the Dieng
Project.
The Company presently intends to develop the Lampung Project
and other possible Indonesia projects using a structure similar to
that contemplated for the Dieng Project, with the same construction
consortium, similar equipment and similar financing arrangements.
The Lampung Project remains subject to a number of significant
uncertainties, as described above for the Dieng Project, and there
can be no assurance that the Company will pursue the Lampung
Project or that it will proceed or reach commercial operation.
REGULATORY AND ENVIRONMENTAL MATTERS
Environmental Regulation
The Company's projects are subject to environmental laws and
regulations at the federal, state and local levels in connection
with the development, ownership and operation of the projects.
These environmental laws and regulations generally require that a
wide variety of permits and other approvals be obtained for the
construction and operation of an energy-producing facility and that
the facility then operate in compliance with such permits and
approvals. Failure to operate the facility in compliance with
applicable laws, permits and approvals can result in the levy of
fines or curtailment of operations by regulatory agencies.
Management of the Coso Joint Ventures believe that the Coso
Joint Ventures are in compliance in all material respects with all
applicable environmental regulatory requirements and that
maintaining compliance with current governmental requirements will
not require a material increase in capital expenditures or
materially affect its financial condition or results of operations.
Likewise, management of the Company believes that the Company's
other projects are in compliance with all applicable environmental
regulatory requirements. It is possible, however, that future
developments, such as more stringent requirements of environmental
laws and enforcement policies thereunder, could affect the costs of
and the manner in which the Coso Joint Ventures or the Company's
other projects conduct their businesses.
Federal Energy Regulations
The principal federal regulatory legislation relating to the
Company's geothermal energy activities is PURPA. PURPA and
associated state legislation have conferred certain benefits on the
independent power production industry. In particular, PURPA
exempts certain electricity producers ("Qualifying Facilities")
from federal and state regulation as a public utility. PURPA also
requires utilities, such as SCE, to purchase electricity from
qualifying facilities at the particular utility's avoided cost.
Each of the Coso Projects meets the requirements promulgated
under PURPA to be Qualifying Facilities. Qualifying Facility
status under PURPA provides two primary benefits. First,
regulations under PURPA exempt qualifying facilities from the
Public Utility Holding Company Act of 1935 ("PUHCA"), most
provisions of the Federal Power Act (the "FPA") and state laws
concerning rates of electric utilities, and financial and
organizational regulations of electric utilities. Second, FERC's
regulations promulgated under PURPA require that (1) electric
utilities purchase electricity generated by Qualifying Facilities,
the construction of which commenced on or after November 9, 1978,
at a price based on the purchasing utility's full avoided cost; (2)
the electric utility sell back-up, interruptable, maintenance and
supplemental power to the Qualifying Facility on a non-
discriminatory basis; and (3) the electric utility interconnect
with the Qualifying Facility in its service territory.
The Projects remain subject, among other things, to FERC
approvals and permits for power development, and to federal, state
and local laws and regulations regarding environmental compliance,
leasing, siting, licensing, construction, and operational and other
matters relating to the exploration, development and operation of
its geothermal properties.
In 1992, Congress enacted comprehensive new energy policy
legislation in its passage of the Energy Policy Act. This new law
is designed to, among other things, foster competition in energy
production and provide independent power producers with competitive
access to the transmission grid. To achieve these goals, the
Energy Policy Act amended PUHCA to create a new class of generating
facility called Exempt Wholesale Generators ("EWGs"). EWGs are
generally exempt from public utility regulation under PUHCA. The
Energy Policy Act also provides new authority to FERC to mandate
that owners of transmission lines provide wheeling access at just
and reasonable rates. Previously limited, wheeling rights enhance
the ability of independent power producers to negotiate
transmission access and encourages development of facilities whose
most feasible siting lies outside the purchasing utility's service
area or which, like many geothermal sites, are remotely located.
Permits and Approvals
The Company has obtained certain permits, approvals and
certificates necessary for the current exploration, development and
operation of its Projects. Similar permits, approvals and
certificates will be required for any future expansion of the Coso
Project and for any development of the Company's other geothermal
properties or for other power project development by the Company.
Such compliance is costly and time consuming, and may in certain
instances be dependent upon factors beyond the Company's control.
The Company believes that its operating power facilities are
currently in material compliance with all applicable federal, state
and local laws and regulations. No assurance can be given,
however, that in the future all necessary permits, approvals,
variances and certificates will be obtained and all applicable
statutes and regulations will be complied with, nor can assurance
be given that additional and more stringent laws, taxes or
regulations will not be established in the future which may
restrict the Company's current operations or delay the development
of new geothermal properties, or which may otherwise have an
adverse impact on the Company.
INSURANCE
The Coso Projects are insured for $600.0 million per
occurrence for general property damage and $600.0 million per
occurrence for business interruption, subject to a $25,000
deductible for property damage ($500,000 for turbine generator and
machinery) and a 15-day deductible for business interruption.
Catastrophic insurance (earthquake and flood) for the Coso Project
is capped at $200.0 million per occurrence for property damage and
$200.0 million per occurrence for business interruption. Liability
insurance coverage is $51.0 million (occurrence based) with a
$10,000 deductible. Operators' extra expense (control of well)
insurance for the Coso Project is $10.0 million per occurrence with
a $25,000 deductible which is non-auditable. The policies are
issued by international and domestic syndicates with each company
rated A- or better by A.M. Best Co., Inc. There can be no
assurance, however, that earthquake, property damage, business
interruption or other insurance will be adequate to cover all
potential losses sustained by the Company or that such insurance
will continue to be available on commercially reasonable terms.
EMPLOYEES
As of December 31, 1993, the Company employed approximately
249 people, of which approximately 160 people were employed at the
Navy I, Navy II and BLM Projects, collectively. The Coso Joint
Ventures do not hire or retain any employees. All employees
necessary to the operation of the Coso Project are provided by the
Company under certain plant and field operations and maintenance
agreements.
Item 2. Properties
As described under "Business", the Company's most significant
physical properties are its four operating power facilities and its
related real property interests. The Company also maintains an
inventory of more than 400,000 acres of geothermal property leases
and owns a 70% interest in a geothermal steam field. An affiliate
of the Company owns the approximately 42 acre site in Yuma, Arizona
where the 50 MW gas fired cogeneration facility is being
constructed.
The Company owns a one-story office building in Omaha,
Nebraska, which houses its principal executive offices. The
Company also leases office space in Ridgecrest, California, which
houses the operating offices for the Coso Project and in Singapore
and Manila, which house offices for the Company's international
activities in the region.
Item 3. Legal Proceedings
The Company is not a party to any material legal proceedings.
Item 4. Submission of Matters to a Vote of Security Holders
Not applicable.
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder's Matters
The Company's Common Stock is listed on the New York
Stock Exchange, the Pacific Stock Exchange and the London Stock
Exchange using the symbol CE. Prior to listing on the New York
Stock Exchange on August 12, 1993, the Company's Common Stock was
listed on the American Stock Exchange.
The following table sets forth, for the calendar periods
indicated, the high and low closing sales prices of the Company's
Common Stock as reported by the American Stock Exchange for the
periods through August 11, 1993 and the New York Stock Exchange
thereafter. All prices have been adjusted to reflect the Company's
stock dividends during those calendar periods.
1992
Period High Low
First Quarter $16.25 $11.63
Second Quarter 13.25 11.50
Third Quarter 13.00 11.38
Fourth Quarter 17.38 11.88
1993
Period High Low
First Quarter 21.50 16.50
Second Quarter 20.00 17.25
Third Quarter 18.38 16.00
Fourth Quarter 20.13 18.13
As of March 21, 1994, there were 1,408 stockholders of record
of the Company's Common Stock.
The present policy of the Board is to retain earnings to
provide sufficient funds for the operation and expansion of the
Company's business. Accordingly, the Company has not paid, and
does not have any present plan to pay, cash dividends on its Common
Stock. In January of 1990 and January of 1991, the Company paid a
4% stock dividend to the holders of its Common Stock. The Company
did not pay such a dividend in 1992 or 1993, and has no plans to
pay any such dividend in the future.
Prior to March 24, 1994, the agreements relating to the Senior
Notes issued by the Company prohibit the payment of dividends
unless the Company has a net worth of at least $50 million, after
giving effect to the payment of such dividends, and dividends do
not exceed 50% of the Company's net income accumulated after
December 31, 1987. Pursuant to a Defeasance Agreement dated March
23, 1994 such restrictions were released by the holder of the
Senior Notes. The Certificate of Designation with respect to the
Company's Series C Redeemable Convertible Exchangeable Preferred
Stock (the "Series C Preferred Stock") prohibits cash dividend
payments with respect to the Common Stock unless all accumulated
dividends on the Series C Preferred Stock have been paid.
The Indenture for the Senior Discount Notes issued by the
Company on March 24, 1994 prohibit the payment of dividends unless
certain financial covenants are satisfied. Reference is made to
the indenture relating to the Senior Discount Notes for a detailed
description of these restrictions.
In June of 1993, the Company issued $100,000,000 of 5%
convertible subordinated debentures ("Debentures") due July 31,
2000. The Debentures are convertible into shares of the Company's
Common Stock at any time prior to redemption or maturity at a
conversion price of $22.50 per share, subject to adjustment in
certain circumstances. Interest on the Debentures is payable semi-
annually in arrears on July 31 and January 31 of each year,
commencing on July 31, 1993. The debentures are redeemable for
cash at any time on or after July 31, 1996 at the option of the
Company. The redemption prices (expressed in percentages of the
principal amount) based on twelve month periods beginning July 31,
1996 are 102%, 101%, 100% and 100% for 1996, 1997, 1998 and 1999,
respectively. The Debentures are unsecured general obligations of
the Company and subordinated to all existing and future senior
indebtedness of the Company. In December of 1993, the Company
registered 4,444,444 shares of the Company's Common Stock in the
event a holder elected to exercise the conversion rights under the
Debentures.
Item 6. Selected Financial Data
There is hereby incorporated by reference the information
which appears under the caption "Selected Financial Data" in the
Annual Report.
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operation
There is hereby incorporated by reference the information
which appears under the caption "Management's Discussion and
Analysis of Financial Condition and Results of Operation" in the
Annual Report.
Item 8. Financial Statements and Supplementary Data
There is hereby incorporated by reference the information
which appears in the Consolidated Financial Statements and notes
thereto in the Annual Report. Since the preparation of the
Consolidated Financial Statements, the Company closed on the Senior
Discount Notes described in the Consolidated Financial Statements
at footnote 16, "Subsequent Event." On March 24, 1994 the Company
received the proceeds of about $390 million from the closing on its
Senior Discount Note offering. The Senior Discount Notes bear
interest at the rate of 10.25% per annum, with cash interest
payment commencing in 1997 and accrete to an aggregate principal
amount of $529 million at maturity. The notes are unsecured
obligations of the Company. The Company intends to use the
proceeds from the offering to: (i) fund equity commitments in, and
the construction costs of, geothermal power project presently
planned in the Philippines and Indonesia, (ii) to fund equity
investments in, and loan to, other potential international and
domestic private power projects and related facilities, (iii) for
corporate or project acquisitions permitted under the indenture,
and (iv) for general corporate purposes.
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
Not Applicable
PART III
Item 10. Directors and Executive Officers of the Registrant
There is hereby incorporated by reference the information
which appears under the caption "Information Regarding Nominees for
Election as Directors and Directors Continuing in Office" in the
Proxy Statement.
Set forth below are the current executive officers of the
Company and their positions with the Company:
Executive Officer Position
Richard R. Jaros Chairman of the Board of Directors
David L. Sokol President and Chief Executive Officer
Gregory E. Abel Assistant Vice President and Controller
Edward F. Bazemore Vice President, Human Resources
David W. Cox Vice President, Legislative and Regulatory
Affairs
Philip H. Essner Vice President, Land Management and Insurance
Vincent R. Fesmire Vice President, Development and
Implementation
Thomas R. Mason Senior Vice President, Engineering,
Construction and Operations
Steven A. McArthur Senior Vice President, General Counsel and
Secretary
Donald M. O'Shei, Sr. Vice President, Marketing;
President, CE International, Ltd.
John G. Sylvia Vice President, Chief Financial Officer and
Treasurer
Set forth below is certain information with respect to each
executive officer of the Company other than Messrs. Jaros and Sokol
(for whom information is incorporated by reference from the Proxy
Statement):
GREGORY E. ABEL, 31, Assistant Vice President and Controller.
Mr. Abel joined the Company in 1992. Mr. Abel is a Chartered
Accountant and from 1984 to 1992 he was employed by Price
Waterhouse. As a Manager in the San Francisco office of Price
Waterhouse, he was responsible for clients in the energy industry.
EDWARD F. BAZEMORE, 57, Vice President, Human Resources. Mr.
Bazemore joined the Company in July 1991. From 1989 to 1991, he
was Vice President, Human Resources, at Ogden Projects, Inc. in New
Jersey. Prior to that, Mr. Bazemore was Director of Human
Resources for Ricoh Corporation, also in New Jersey. Previously,
he was Director of Industrial Relations for Scripto, Inc. in
Atlanta, Georgia.
DAVID W. COX, 38, Vice President, Legislative and Regulatory
Affairs. Mr. Cox joined the Company in 1990. From 1987 to 1990,
Mr. Cox was Vice President with Bank of America N.T. & S.A. in the
Consumer Technology and Finance Group. From 1984 to 1987, Mr. Cox
held a variety of management positions at First Interstate Bank.
PHILIP H. ESSNER, 51, Vice President, Land Management and
Insurance. Mr. Essner administers the Company's geothermal lease
acquisition and land position programs, and obtains permits from
regulatory agencies. Mr. Essner also manages the Company's
insurance programs. He has been a Vice President of the Company
since 1983.
VINCENT R. FESMIRE, 53, Vice President, Development and
Implementation. Mr. Fesmire joined the Company in October 1993.
Prior to joining the Company, Mr. Fesmire was employed for 19 years
with Stone & Webster, an engineering firm, serving in various
management level capacities with an expertise in geothermal design
engineering.
THOMAS R. MASON, 50, Senior Vice President, Engineering,
Construction and Operations. Mr. Mason joined the Company in March
1991. From October 1989 to March 1991, Mr. Mason was Vice
President and General Manager of Kiewit Energy Company. Mr. Mason
acted as a consultant in the energy field from June 1988 to October
1989. Prior to that, Mr. Mason was Director of Marketing for
Energy Factors, Inc., a non-utility developer of power facilities.
STEVEN A. McARTHUR, 36, Senior Vice President, General Counsel
and Secretary. Mr. McArthur joined the Company in February 1991.
From 1988 to 1991 he was an attorney in the Corporate Finance Group
at Shearman & Sterling in San Francisco. From 1984 to 1988 he was
an attorney in the Corporate Finance Group at Winthrop, Stimson,
Putnam & Roberts in New York.
DONALD M. O'SHEI, SR., 60, Vice President; President, CE
International, Ltd. General O'Shei was in charge of engineering
and operations for the Company from October 1988 until October
1991. He rejoined the Company as a Vice President in August, 1992.
Previously he was President and Chief Executive Officer of AWD
Technologies, Inc., a hazardous waste remediation firm, and
President and General Manager of its predecessor company, Atkinson-
Woodward Clyde. He was a brigadier general in the U.S. Army prior
to joining the Guy F. Atkinson Co. in 1982 as Director of Corporate
Planning and Development.
JOHN G. SYLVIA, 35, Vice President, Chief Financial Officer
and Treasurer. Mr. Sylvia joined the Company in 1988. From 1985
to 1988, Mr. Sylvia was a Vice President in the San Francisco
office of the Royal Bank of Canada, with responsibility for
corporate and capital markets banking. From 1986 to 1990, Mr.
Sylvia served as an Adjunct Professor of Applied Economics at the
University of San Francisco. From 1982 to 1985, Mr. Sylvia was a
Vice President with Bank of America.
Item 11. Executive Compensation
There is hereby incorporated by reference the information
which appears under the caption "Executive Officer and Director
Compensation" in the Proxy Statement.
Item 12. Security Ownership of Certain Beneficial Owners and
Management
There is hereby incorporated by reference the information
which appears under the caption "Security Ownership of Significant
Stockholders and Management" in the Proxy Statement.
Item 13. Certain Relationships and Related Transactions
There is hereby incorporated by reference the information
which appears under the caption "Certain Transactions and
Relationships" in the Proxy Statement.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K
(a) Financial Statements and Schedules
(i) Financial Statements
Filed herewith are the consolidated balance
sheet of California Energy Company, Inc. and subsidiaries as of
December 31, 1993, and December 31, 1992, and the consolidated
statements of operations, cash flows and stockholder's equity for
the years ended December 31, 1993, 1992 and 1991, and the related
reports of independent auditors.
(ii) Financial Statement Schedules
Schedule No. Name of Schedule
II Amounts Receivable from Related Parties
and Underwriters, Promoters, and
Employees other than Related Parties
III Financial Statements of the Company
(Parent Company only)
V Consolidated Property, Plant and
Equipment
VI Consolidated Accumulated Depreciation and
Amortization of Property, Plant and
Equipment
IX Short-Term Borrowings
X Consolidated Supplementary Income
Statement Information
The other financial statement schedules are
either not required for the Company or are included at the notes to
the financial statements.
(b) Reports on Form 8-K
The Company filed a Report on Form 8-K on October 1,
1993 reporting the signing of Energy Conversion Agreement with the
Philippine National Oil Company - Energy Development Corporation
for two separate Philippines geothermal power projects totaling 300
MW under Item 5. thereof, "Other Events".
The Company filed a Report on Form 8-K on November
2, 1993 reporting the Company agreed to acquire 100% of the stock
of Westmoreland Energy, Inc. from Westmoreland Coal Company.
The Company filed a Report on Form 8-K on December
1, 1993 reporting that it terminated the proposed acquisition of
Westmoreland Energy, Inc. stock.
(c) Exhibits
The exhibits listed on the accompanying Exhibit
Index (except in the case of Exhibit 13.0, in which case only the
portion of the Annual Report which constitutes the Company's
Consolidated Financial Statements and notes thereto) are filed as
part of this Annual Report.
For the purposes of complying with the amendments to
the rules governing Form S-8 effective July 13, 1990 under the
Securities Act of 1933, the undersigned Registrant hereby
undertakes as follows, which undertaking shall be incorporated by
reference into the Company's currently effective Registration
Statements on Form S-8:
Insofar as indemnification for liabilities arising
under the Securities Act of 1933 may be permitted to directors,
officers and controlling persons of the registrant, the registrant
has been advised that in the opinion of the Securities and Exchange
Commission such indemnification is against public policy as
expressed in the Securities Act of 1933 and is, therefore,
unenforceable. In the event that a claim for indemnification
against such liabilities (other than the payment by the registrant
of expenses incurred or paid by a director, officer of controlling
person of the registrant in the successful defense of any action,
suit or proceeding) is asserted by such director, officer or
controlling person in connection with the securities being
registered, the registrant will, unless in the opinion of its
counsel the matter has been settled by controlling precedent,
submit to a court of appropriate jurisdiction the question whether
such indemnification by it is against public policy as expressed
in the Act and will be governed by the final adjudication of such
issue.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused
this report to be signed on its behalf by the undersigned thereunto
duly authorized, in the City of Omaha, State of Nebraska, on this
30th day of March, 1994.
CALIFORNIA ENERGY COMPANY, INC.
By David L. Sokol
President and Chief Executive Officer
By: /s/ Steven A. McArthur
Steven A. McArthur
Attorney-in-Fact
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the Registrant and in the capacities and on the dates
indicated.
Signature Date
/s/ David L. Sokol* March 30, 1994
David L. Sokol
President and Chief Executive
Officer, Director
/s/ John G. Sylvia March 30, 1994
John G. Sylvia
Vice President, Chief Financial
Officer, Chief Accounting Officer
and Treasurer
*By: /s/ Steven A. McArthur March 30, 1994
Steven A. McArthur
Attorney-in-Fact
/s/ Edgar D. Aronson * March 30, 1994
Edgar D. Aronson
Director
/s/ Judith E. Ayres * March 30, 1994
Judith E. Ayres
Director
/s/ Harvey F. Brush* March 30, 1994
Harvey F. Brush
Director
/s/ James Q. Crowe* March 30, 1994
James Q. Crowe
Director
/s/ Richard K. Davidson* March 30, 1994
Richard K. Davidson
Director
/s/ Richard R. Jaros* March 30, 1994
Richard R. Jaros
Chairman of the Board of Directors
/s/ Ben Holt* March 30, 1994
Ben Holt
Director
/s/ Everett B. Laybourne* March 30, 1994
Everett B. Laybourne
Director
/s/ Daniel J. Murphy* March 30, 1994
Daniel J. Murphy
Director
/s/ Herbert L. Oakes, Jr.* March 30, 1994
Herbert L. Oakes, Jr.
Director
/s/ Walter Scott, Jr.* March 30, 1994
Walter Scott, Jr.
Director
/s/ Barton W. Shackelford* March 30, 1994
Barton W. Shackelford
Director
/s/ David E. Wit* March 30, 1994
David E. Wit
Director
*By: /s/ Steven A. McArthur March 30, 1994
Steven A. McArthur
Attorney-in-Fact
<PAGE>
California Energy Company, Inc. Schedule II
Amounts Receivable from Related Parties and Underwriters,
Promoters, and Employees Other Than Related Parties
as of December 31, 1993, 1992, 1991
(dollars in thousands)
Balance at
Beginning
of Period Additions Collected Current Noncurrent
Year ended December 31, 1993 $--- $--- $--- $--- $---
Year ended December 31, 1992 --- --- --- --- ---
Year ended December 31, 1991 100 --- 100 --- ---
Robert D. Tibbs*
*Relocation Loan, repaid January 2, 1991
California Energy Company, Inc. Schedule III
Parent Company Only
Balance Sheets
as of December 31, 1993 and 1992
(dollars and shares in thousands, except per share amounts)
ASSETS 1993 1992
Cash and investments $126,824 $ 53,321
Restricted cash 13,535 634
Development projects in progress 44,272 21,428
Investment in and advances to subsidiaries
and joint ventures 215,660 168,949
Equipment, net of accumulated depreciation 2,587 1,575
Notes receivable - joint ventures 21,558 19,098
Deferred charges and other assets 16,458 17,214
Total assets $440,894 $282,219
LIABILITIES AND STOCKHOLDERS' EQUITY
Liabilities:
Accounts payable $ 86 $ 937
Other accrued liabilities 10,550 5,061
Income taxes payable 4,000 ---
Senior notes 35,730 35,730
Convertible subordinated debenture 100,000 ---
Deferred income taxes 18,310 15,212
Total liabilities 168,676 56,940
Deferred income relating to joint ventures 1,915 2,165
Redeemable preferred stock 58,800 54,350
Stockholders' equity:
Preferred stock - authorized 2,000
shares no par value --- ---
Common stock - authorized 60,000
shares par value $0.0675 per share;
issued and outstanding 35,446 and
35,258 shares 2,404 2,380
Additional paid-in capital 100,965 97,977
Retained earnings 111,031 68,407
Treasury stock, 157 common shares at cost (2,897) ---
Total stockholders' equity 211,503 168,764
Total liabilities and stockholders' equity $440,894 $282,219
The accompanying notes are an integral part of these financial statements.
California Energy Company, Inc. Schedule III
Parent Company Only (continued)
Statement of Operations
for the three years ended December 31, 1993
(dollars in thousands)
Revenues: 1993 1992 1991
Equity in earnings of subsidiary
companies and joint ventures before
extraordinary items $61,412 $53,685 $38,364
Interest and other income 8,756 4,557 4,923
Total revenues 70,168 58,242 43,287
Expenses:
General and administration 6,564 6,796 5,585
Interest, net of capitalized interest 2,346 714 2,836
Total expenses 8,910 7,510 8,421
Income before provision for income
taxes 61,258 50,732 34,866
Provision for income taxes 18,184 11,922 8,284
Income before change in accounting
principle and extraordinary item 43,074 38,810 26,582
Cumulative effect of change in
account principle 4,100 --- ---
Equity in extraordinary item of joint
ventures (Less applicable income taxes
of $1,533) --- (4,991) ---
Net income 47,174 33,819 26,582
Preferred dividends 4,630 4,275 ---
Net income available
to common stockholders $42,544 $29,544 $26,582
The accompanying notes are an integral part of these financial statement.
California Energy Company, Inc. Schedule III
Parent Company Only (continued)
Condensed Statement of Cash Flows
for the three years ended December 31, 1993
(dollars in thousands)
1993 1992 1991
Cash flows from operating activities $45,671 $22,597 $ 631
Cash flows from investing activities:
Increase in development projects
in progress (22,844) (4,218) (3,458)
Decrease (increase) in advances
to and investments in subsidiaries
and joint ventures (36,812) 12,155 (41,162)
Other (9,945) (15,711) 251
Cash flows from investing activities (69,601) (7,774) (44,369)
Cash flows from financing activities:
Proceeds from sale of common,
treasury and preferred stocks,
and exercise of warrants and
stock options 2,912 8,065 111,458
Payment in senior notes --- --- (6,000)
Purchase of treasury stock (2,897) (4,887) ---
Net change in short-term bank loan --- --- (15,000)
Proceeds from issue of convertible
subordinated debentures 100,000 --- ---
Purchase of warrants --- (11,716) ---
Deferred charges relating to debt
financing (2,582) --- ---
Cash flows from financing activities 97,433 (8,538) 90,458
Net increase in cash
and investments 73,503 6,285 46,720
Cash and investments at beginning
of period 53,321 47,036 316
Cash and investment at end of period $126,824 $53,321 $47,036
Interest paid (net of amount
capitalized) $ (897) $ 464 $ 3,342
Income taxes paid $ 6,819 $ 4,129 $ 1,682
The accompanying notes are an integral part of these financial statement.
California Energy Company, Inc. Schedule III
Parent Company Only (continued)
Supplemental Notes to Financial Statement
(dollars in thousands)
Related Party Transactions
The Company bills the Coso Project partnerships and joint ventures for
management, professional and operational services. Billings for the
years ended December 31, 1993, 1992 and 1991 were $18,285, $19,629 and
$18,316, respectively. Dividends received from subsidiaries for the
years ended December 31, 1993, 1992 and 1991 were $49,053, $33,524 and
18,935, respectively.
Reclassification
Certain amounts in the fiscal 1992 and 1991 financial statements have been
reclassified to conform to the fiscal 1993 presentation. Such
reclassifications do not impact previously reported net income or retained
earnings.
California Energy Company, Inc. Schedule V
Consolidated Property, Plant and Equipment
as of December 31, 1993, 1992, and 1991
(dollars in thousands)
<TABLE>
<CAPTION>
Balance at Balance
Beginning Additions Other at end
Asset Description of Period at Cost Retirement Changes of Period
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1993
Power plant and gathering system $235,924 $ 10,295 $ --- $ --- $ 246,219
Wells and resources development costs 144,595 16,542 --- --- 161,137
Total operating facilities 380,519 26,837 --- --- 407,356
Wells and resource construction in
progress 916 23 --- --- 939
Total project costs 381,435 26,860 408,295
Pacific Northwest Properties costs 25,882 15,657 --- --- 41,539
Nevada and Utah properties costs 32,089 3,403 --- --- 35,492
Yuma - construction in progress 1,294 40,167 --- --- 41,461
Equipment 8,308 1,104 --- (99)(1) 9,313
$449,008 $ 87,191 $ --- $ (99)(1) $ 536,100
Year ended December 31, 1992
Power plant and gathering system $229,213 $ 6,711 $ --- $ --- $ 235,924
Wells and resource development costs 124,416 19,029 --- 1,150(1) 144,595
Total operating facilities 353,629 25,740 --- 1,150(1) 380,519
Wells and resource construction in
progress 1,892 174 --- (1,150)(1) 916
Total project costs 355,521 25,914 --- --- 381,435
Pacific Northwest properties costs 22,627 3,255 --- --- 25,882
Nevada and Utah properties costs 31,199 890 --- --- 32,089
Yuma - construction in progress --- 1,294 --- --- 1,294
Equipment 7,215 1,093 --- --- 8,308
$416,562 $ 32,446 $ --- $ --- $ 449,008
Year ended December 31, 1991
Power plant and gathering system $221,991 $ 7,784 --- (562)(1) $ 229,213
Wells and resource development costs 92,280 31,574 --- 562 (1) 124,416
Total operating facilities 314,271 39,358 --- --- 353,629
Wells and resource development costs 1,812 80 --- --- 1,892
Total project costs 316,083 39,438 --- --- 355,521
Pacific Northwest properties costs 18,761 3,866 --- --- 22,627
Nevada and Utah properties costs 8,028 23,171 --- --- 31,199
Equipment 6,898 1,027 (710) --- 7,215
$349,770 $ 67,502 $ (710) --- $ 416,562
<FN>
(1) Other reclassifications
</TABLE>
California Energy Company, Inc. SCHEDULE VI
Consolidated Accumulated Depreciation and Amortization
of Property, Plant and Equipment
as of December 31, 1993, 1992, and 1991
(dollars in thousands)
<TABLE>
<CAPTION>
Balance at Depreciation Balance
Beginning and Other at end
of Period Amortization Retirements Changes of Period
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1993
Power Plant and gathering system $21,947 $ 6,844 $ --- $ (276)* $28,515
Wells and resource development costs 29,107 10,191 --- --- 39,298
Total operating facilities 51,054 17,035 --- (276) 67,813
Equipment 3,996 777 --- --- 4,773
$55,050 $17,812 $ --- $ (276) $72,586
Year ended December 31, 1992
Power Plant and gathering system $15,812 $ 6,135 $ --- $ --- $21,947
Wells and resource development costs 19,587 9,520 --- --- 29,107
Total operating facilities 35,399 15,655 --- --- 51,054
Equipment 2,897 1,099 --- --- 3,996
$38,296 $16,754 $ --- $ --- $55,050
Year ended December 31, 1991
Power Plant and gathering system $ 9,885 $ 5,927 $ --- $ --- $15,812
Wells and resource development costs 11,684 7,903 --- --- 19,587
Total operating facilities 21,569 13,830 --- --- 35,399
Equipment 2,251 922 (276) --- 2,897
$23,820 $14,752 $ (276) $ --- $38,296
<FN>
*Reclassification.
</TABLE>
California Energy Company, Inc. SCHEDULE IX
Short-Term Borrowings
as of December 31, 1993, 1992, and 1991
(dollars in thousands)
<TABLE>
<CAPTION>
Weighted average Maximum amount Average amount Weighted average
Category of aggregate Balance at end interest rate outstanding outstanding interest rate during
short-term borrowings of period during the period during the period the period
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1993 $ --- --- $ --- $ --- ---
Year ended December 31, 1992 $ --- --- --- --- ---
Year ended December 31, 1991 $ --- 7.21% $15,000 $ 8,125 8.5%
</TABLE>
The short-term borrowing payable to a bank was under a $15,000 multi-year
Credit Agreement. The average amount outstanding during the period was
computed based on month-end balances. The weighted average interest rate
during the period was the effective rate incurred.
California Energy Company, Inc. Schedule X
Consolidated Supplementary Income Statement Information
for the three years ended December 31, 1993
(dollars in thousands)
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Maintenance and repairs $ 3,465 $ 3,337 $ 2,283
Amortization of deferred financing cost $ 1,031 $ 1,232 $ 964
Taxes, other than payroll and income taxes $ 3,902 $ 3,572 $ 3,603
Royalties $ 8,274 $ 7,710 $ 5,505
Advertising costs * * *
<FN>
*Less than amounts required to be reported pursuant to Securities and Exchange Commission
</TABLE>
<PAGE>
Exhibit Index
3.1 The Company's Restated Certificate of Incorporation
(incorporated by reference to Exhibit 3.1 of the Company's
Form 10-K for the year ended December 31, 1992, File No. 1-
9874 (the "1992 Form 10-K"))
3.2 Certificate of Amendment of the Company's Restated Certificate
of Incorporation, dated June 23, 1993 (incorporated by
reference to the Company's Form 8-A, dated July 28, 1993, File
No. 1-9874 (the "Form 8-A"))
3.3 The Company's Certificate of Designation with respect to the
Company's Series C Redeemable Convertible Exchangeable
Preferred Stock, dated November 20, 1991 (incorporated by
reference to Exhibit 3.1 of the Company's 1992 Form 10-K)
3.4 The Company's By-Laws as amended through September 24, 1993.
4.1 Specimen copy of form of Common Stock Certificate.
4.2 Shareholders Rights Agreement between the Company and
Manufacturers Hanover Trust Company of California dated
December 1, 1988 (incorporated by reference to Exhibit 1 to
Company's Form 8-K dated December 5, 1988, File No. 1-9874).
4.3 Amendment Number 1 to Shareholder Rights Agreement, dated
February 15, 1991 (incorporated by reference to Exhibit 4.2 to
the Company's 1992 Form 10-K).
4.4 Note Purchase Agreement between the Company and Principal
Mutual Life Insurance Company dated March 15, 1988
(incorporated by reference to Exhibit 1 to Company's Form 8-K
dated April 11, 1988).
4.5 Defeasance Agreement between Principal Mutual Life Insurance
Company and the Company dated March 3, 1994.
4.6 Consent and Agreement between Principal Mutual Life Insurance
Company and the Company dated March 24, 1994.
4.7 Escrow Deposit Agreement between Bank of America National
Trust and Savings Association and the Company dated March 3,
1994.
10.1 Joint Venture Agreement for China Lake Joint Venture between
the Company and Caithness Geothermal 1980 Ltd., restated as of
January 1, 1984 (incorporated by reference to Exhibit 10.1 to
the Company's Registration Statement on Form S-1, 33-7770).
10.2 Amended Joint Venture Agreement for Coso Land Company between
the Company and Caithness Geothermal 1980 Ltd., dated as of
June 1, 1983 (incorporated by reference to Exhibit 10.3 to the
Company's Registration Statement on Form S-1, 33-7770).
10.3 Amended General Partnership Agreement for Coso Finance
Partners between China Lake Operating Company and ESCA I L.P.
dated July 13, 1988 (incorporated by reference to Exhibit 10.3
to the Company's 1992 Form 10-K).
10.4 First Supplemental Amendment to the Amended and Restated
General Partnership Agreement for Coso Finance Partners
between China Lake Operating Company and ESCA L.P. (Undated)
(incorporated by reference to Exhibit 10.4 to the Company's
1992 Form 10-K).
10.5 Second Supplemental Amendment to the Amended and Restated
General Partnership Agreement for Coso Finance Partners
between China Lake Operating Company and ESCA L.P. dated as of
July 13, 1988 (incorporated by reference to Exhibit 10.5 to
the Company's 1992 Form 10-K).
10.6 Third Supplemental Amendment to the Amended and Restated
General Partnership Agreement for Coso Finance Partners
between China Lake Operating Company and ESCA L.P. dated as of
December 16, 1992 (incorporated by reference to Exhibit 10.6
to the Company's 1992 Form 10-K).
10.7 General Partnership Agreement for Coso Finance Partners II
between China Lake Geothermal Management Company and ESCA II
L.P. dated July 7, 1987 (incorporated by reference to Exhibit
10.7 to the Company's 1992 Form 10-K).
10.8 Restated General Partnership Agreement for Coso Energy
Developers between Coso Hotsprings Intermountain Power Inc.
and Caithness Coso Holdings L.P. dated as of March 31, 1988
(incorporated by reference to Exhibit 10.8 to the Company's
1992 Form 10-K).
10.9 First Amendment to the Restated General Partnership Agreement
for Coso Energy Developers between Coso Hotsprings
Intermountain Power, Inc. and Caithness Coso Holdings L.P.
dated as of March 31, 1988 (incorporated by reference to
Exhibit 10.9 to the Company's 1992 Form 10-K).
10.10 Second Amendment to the Restated General Partnership
Agreement for Coso Energy Developers between Coso
Hotsprings Intermountain Power, Inc. and Caithness Coso
Holdings L.P. dated as of December 16, 1992 (incorporated
by reference to Exhibit 10.10 to the Company's 1992 Form
10-K).
10.11 Amended and Restated General Partnership Agreement for
Coso Power Developers between Coso Technology Corporation
and Caithness Navy II Group L.P. dated July 31, 1989
(incorporated by reference to Exhibit 10.11 to the
Company's 1992 Form 10-K).
10.12 First Amendment to the Amended and Restated General
Partnership for Coso Power Developers between Coso
Technology Corporation and Caithness Navy II Group L.P.
dated as of March 19, 1991 (incorporated by reference to
Exhibit 10.12 to the Company's 1992 Form 10-K).
10.13 Second Amendment to the Amended and Restated General
Partnership Agreement for Coso Power Developers between
Coso Technology Corporation and Caithness Navy II Group
L.P. dated as of December 16, 1992 (incorporated by
reference to Exhibit 10.13 to the Company's 1992 Form 10-K).
10.14 Form of Amended and Restated Field Operation and
Maintenance Agreement between Coso Joint Ventures and the
Company dated as of December 16, 1992 (incorporated by
reference to Exhibit 10.14 to the Company's 1992 Form 10-K).
10.15 Form of Amended and Restated Project Operation and
Maintenance Agreement between Coso Joint Venture and the
Company dated as of December 16, 1992 (incorporated by
reference to Exhibit 10.15 to the Company's 1992 Form 10-K).
10.16 Trust Indenture between Coso Funding Corp. and Bank of
America National Trust and Savings Association dated as
of December 16, 1992 (incorporated by reference to
Exhibit 10.16 to the Company's 1992 Form 10-K).
10.17 Form of Amended and Restated Credit Agreement between
Coso Funding Corp. and Coso Joint Ventures dated as of
December 16, 1992 (incorporated by reference to Exhibit
10.17 to the Company's 1992 Form 10-K).
10.18 Form of Support Loan Agreement among Coso Joint Ventures
dated December 16, 1992 (incorporated by reference to
Exhibit 10.18 to the Company's 1992 Form 10-K).
10.19 Form of Project Loan Pledge Agreement between Coso Joint
Ventures and Bank of America National Trust and Savings
dated as of December 16, 1992 (incorporated by reference
to Exhibit 10.19 to the Company's 1992 Form 10-K).
10.20 Power Purchase Contracts between Southern California
Edison Company and:
(a) China Lake Joint Venture, executed June 4, 1984 with a
term of 24 years;
(b) China Lake Joint Venture, executed February 1, 1985 with
a term of 23 years; and
(c) Coso Geothermal Company, executed February 1, 1985 with
a term of 30 years (incorporated by reference to Exhibit
10.7 to the Company's Registration Statement on Form S-1,
33-7770).
10.21 Contract No. N62474-79-C-5382 between the United States
of America and China Lake Joint Venture, restated October
19, 1983 as "Modification P00004," including
modifications through "Modification P00026," dated
December 16, 1992 (incorporated by reference to Exhibit
10.21 to the Company's 1992 Form 10-K).
10.22 Lease between the BLM and Coso Land Company, effective
November 1, 1985 (with Designation of Geothermal
Operator) (incorporated by reference to Exhibit 10.8 to
the Company's Registration Statement on Form S-1, 33-
7770).
10.23 Stock Purchase Agreement between the Company and Kiewit
Energy Company dated as of February 18, 1991, as amended
as of June 19, 1991 (incorporated by reference to
Exhibit 1 to the Company's Form 8-K dated February 26,
1991).
10.24 Amendment No. 2 to Stock Purchase Agreement between
Kiewit Energy Company and the Company dated as of January
8, 1992 (incorporated by reference to Exhibit 10.24 to
the Company's 1992 Form 10-K).
10.25 Amendment No. 3 to Stock Purchase Agreement between
Kiewit Energy Company and the Company dated as of April
2, 1993.
10.26 Shareholders Agreement between the Company and Kiewit
Energy Company dated as of February 18, 1991, as amended
as of June 19, 1991 and as of November 20, 1991
(incorporated by reference to Exhibit 1 to the Company's
Form 8-K dated February 26, 1991, Exhibit 1 to the
Company's Form 8-K dated July 18, 1992, and Exhibit 3 to
the Company's Form 8-K dated November 21, 1991).
10.27 Amendment No. 3 to Shareholder's Agreement between the
Company and Kiewit Energy Company dated as of April 2,
1993 (incorporated by reference to Exhibit 14 to the
Company's Form 8-A).
10.28 Amendment No. 4 to Shareholder's Agreement between the
Company and Kiewit Energy Company dated as of July 20,
1993.
10.29 Registration Rights Agreement between the Company and
Kiewit Energy Company dated as of February 18 1991, as
amended as of June 19, 1991 (incorporated by reference to
Exhibit 1 to the Company's Form 8-K dated February 26,
1991, and Exhibit 1 to the Company's Form 8-K dated July
18, 1992).
10.30 Registration Rights Agreement between the Company and
Kiewit Energy Company dated June 19, 1991, as amended
November 20, 1991 (incorporated by reference to Exhibit
1 of the Company's Form 8-K dated June 19, 1991 and
Exhibit 4 to the Company's Form 8-K dated November 21,
1991).
10.31 Stock Option Agreement between the Company and Kiewit
Energy Company dated as of February 18, 1991, as amended
as of June 19, 1991 (incorporated by reference to Exhibit
1 to the Company's Form 8-K dated February 26, 1991, and
Exhibit 1 to the Company's Form 8-K dated July 18, 1992).
10.32 Stock Option Agreement between the Company and Kiewit
Energy Company dated as of June 19, 1991 (incorporated by
reference to Exhibit 1 to the Company's Form 8-K dated
July 18, 1991).
10.33 Securities Purchase Agreement between the Company and
Kiewit Energy Company dated as of November 20, 1991
(incorporated by reference to Exhibit 2 to the Company's
Form 8-K dated November 21, 1991).
10.34 Sublease between the Company and Kiewit Energy Company
dated March 15, 1991 (incorporated by reference to
Exhibit 10.32 to the Company's 1992 Form 10-K).
10.35 Amended and Restated 1986 Stock Option Plan, as amended
(incorporated by reference to Exhibit 10.33 to the
Company's 1992 Form 10-K).
10.36 Form of severance letter between the Company and certain
executive officers of the Company (incorporated by
reference to Exhibit 10.35 to the Company's 1992 Form 10-
K).
10.37 Indenture between the Company and The Chemical Trust
Company of California dated as of June 24, 1993
(incorporated by reference to the Company's Form 8-K
dated June 24, 1993, File No. 1-9874).
10.38 Registration Rights Agreement among the Company, Lehman
Brothers, Inc. and Alex Brown & Sons Incorporated dated
June 24, 1993 (incorporated by reference to the Company's
Form 8-K dated June 24, 1993, File No. 1-9874).
10.39 Indenture dated March 24, 1994 between the Company and
IBJ Schroder Bank and Trust Company (incorporated by
reference to Exhibit 3 to the Company's Form 8-K dated
March 28, 1994).
10.40 Employment Agreement between the Company and David L.
Sokol dated as of April 2, 1993.
10.41 Termination Agreement between the Company and Richard R.
Jaros dated as of December 9, 1993.
10.42 Standard Offer Number 2, Standard Offer for Power
Purchase with a Firm Capacity Qualifying Facility
effective June 15, 1990 ("SO2") between San Diego Gas &
Electric Company and Bonneville Pacific Corporation.
10.43 Amendment Number One to the SO2 dated September 25, 1990.
10.44 Joint Venture Agreement among the Company, Kiewit
Diversified Group Inc. and Kiewit Construction Group Inc.
dated December 14, 1993.
10.45 Joint Venture Agreement between the Company and Distral
dated December 14, 1993.
11.0 Calculation of Earnings Per Share in accordance with
Interpretive Release No. 34-9083.
13.0 The Company's 1993 Annual Report (only the portions thereof
specifically incorporated herein by reference are deemed filed
herewith).
21.0 Subsidiaries of Registrant.
23.0 Consents of Independent Accountants.
24.0 Power of Attorney.
27.0 Financial Data Schedule.
BY-LAWS AS AMENDED THROUGH SEPTEMBER 24, 1993
B Y - L A W S
OF
CALIFORNIA ENERGY COMPANY, INC.
(Formerly Phydeaux Corporation)
a Delaware corporation
ARTICLE I
MEETINGS OF STOCKHOLDERS
Section 1. Annual Meeting. The annual meeting of the stockholders of
California Energy Company, Inc. (hereinafter called the "Corporation") shall
be held at 10:00 a.m. on such day in the month of May in each year as shall
be selected by the President, or, failing such selection, by the Board of
Directors. At the annual meeting, the stockholders shall elect by a plurality
vote a board of directors (hereinafter referred to as "Board"), and transact
such other business as may properly be brought before the meeting. If the
annual meeting shall not be held on the day hereinabove provided for, the
Board shall cause the meeting to be held as soon thereafter as convenient.
Section 2. Special Meetings. Special meetings of the stockholders may be
called for any purpose or purposes at any time only by the Board or the
President, upon not less than ten nor more than fifty days written notice.
Special meetings may not be called by the stockholders.
Section 3. Notice of Meetings. Notice of the place, date and time of the
holding of each annual and special meeting of the stockholders and, in the
case of a special meeting, the purpose or purposes thereof, shall be given
personally or by mail in a postage prepaid envelope to each stockholder
entitled to vote at such meeting, not less than ten nor more than fifty days
before the date of such meeting, and, if mailed, it shall be directed to such
stockholder at his address as it appears on the records of the Corporation,
unless he shall have filed with the Secretary of the Corporation a written
request that notices to him be mailed to some other address, in which case it
shall be directed to him at such other address. Notice of any meeting of
stockholders shall not be required to be given to any stockholder who shall
attend such meeting in person or by proxy and shall not, at the beginning of
such meeting, object to the transaction of any business because the meeting
is not lawfully called or convened, or who shall, either before or after the
meeting, sign a waiver. Notice of an adjourned meeting need not be given if
the time and place to which the meeting shall be adjourned were announced at
the meeting at which the adjournment is taken. At the adjourned meeting the
Corporation may transact any business which might have been transacted at the
original meeting. If the adjournment is for more than thirty days, or if
after the adjournment a new record date is fixed for the adjourned meeting,
a notice of the adjourned meeting shall be given to each stockholder of record
entitled to vote at the meeting.
Section 4. Place of Meetings. Meetings of the stockholders may be held
at such place, within or without the State of Delaware, as the Board or the
officer calling the same shall specify in the notice of such meeting, or in
a duly executed waiver of notice thereof.
Section 5. Quorum. (a) At all meetings of the stockholders, the holders
of a majority of the shares of stock of the Corporation issued and outstanding
and entitled to vote shall be present in person or by proxy to constitute a
quorum for the transaction of any business (except business referred to in
subsection (b) below), except when stockholders are required to vote by class,
in which event a majority of the issued and outstanding shares of the
appropriate class shall be present in person or by proxy, or except as
otherwise provided by statute. (b) At all meetings of the stockholders in
which the action to be taken requires the approval of sixty-six and two-thirds
percent (66 2/3%) of the issued and outstanding shares of stock entitled to
vote, the holders of sixty-six and two-thirds percent (66 2/3%) of the shares
of stock of the Corporation issued and outstanding and entitled to vote shall
be present in person or by proxy in order to constitute a quorum for the
transaction of any such business, except when stockholders are required to
vote by class, in which event, sixty-six and two-thirds percent (66 2/3%) of
the issued and outstanding shares of the appropriate class shall be present
in person or by proxy, or except as otherwise provided by statute. (c) In
the absence of a quorum, the holders of a majority of the shares of stock
present in person or by proxy and entitled to vote, or if no stockholder
entitled to vote is present, then any officer of the Corporation, may adjourn
the meeting from time to time. At any such adjourned meeting at which a
quorum may be present any business may be transacted which might have been
transacted at the meeting as originally called.
Section 6. Organization. At each meeting of the stockholders the
Chairman of the Board, or in his absence or inability to act, the President,
or in the absence or inability to act of the Chairman of the Board or
President, a Vice President, or in the absence of all of the foregoing, any
person chosen by a majority of those stockholders present, shall act as
chairman of the meeting. The Secretary, or in his absence or inability to
act, the Assistant Secretary or any person appointed by the chairman of the
meeting, shall act as secretary of the meeting and keep the minutes thereof.
Section 7. Order of Business. The order of business at all meetings of
the stockholders shall be as determined by the chairman of the meeting.
Section 8. Voting. Except as otherwise required by statute or by the
Certificate of Incorporation, each holder of record of shares of stock of the
Corporation having voting power shall be entitled at each meeting of the
stockholders to one vote for every share of such stock standing in his name
on the record of stockholders of the Corporation on the date fixed by the
Board as the record date for the determination of the stockholders who shall
be entitled to notice of and to vote at such meeting; or at the close of
business on the day next preceding the day on which notice thereof shall be
given, or if notice is waived, at the close of business on the day next
preceding the day on which the meeting is held; or each stockholder entitled
to vote at any meeting of stockholders may authorize another person or persons
to act for him by a proxy signed by such stockholder or his attorney-in-fact.
Any such proxy shall be delivered to the secretary of such meeting at or prior
to the time designated in the order of business for so delivering such
proxies. No proxy shall be valid after the expiration of three years from the
date thereof, unless otherwise provided in the proxy. Every proxy shall be
revocable at the pleasure of the stockholder executing it, except in those
cases where an irrevocable proxy is permitted by law. Except as otherwise
provided by statute, these By-Laws, or the Certificate of Incorporation, any
corporate action to be taken by vote of the stockholders shall be authorized
by a majority of the total votes, or when stockholders are required to vote
by class by a majority of the votes of the appropriate class, cast at a
meeting of stockholders by the holders of shares present in person or
represented by proxy and entitled to vote on such action. Unless required to
be advisable, the vote on any question need not be by written ballot. On a
vote by written ballot, each ballot shall be
signed by the stockholder voting, or by his proxy, if there by such proxy, and
shall state the number of shares voted.
Section 9. List of Stockholders. The officer who has charge of the stock
ledger of the Corporation shall prepare and make, at least ten days before
every meeting of stockholders, a complete list of the stockholders entitled
to vote at that meeting, arranged in alphabetical order, and showing the
addresses of each stockholder and the number of shares registered in the name
of each stockholder. Such list shall be open to the examination of any
stockholder, for any purpose germane to the meeting, during ordinary business
hours, for a period of at least ten days prior to the meeting, either at a
place within the city where the meeting is to be held, which place shall be
specified in the notice of the meeting, or if not so specified, at the place
where the meeting is to be held. The list shall also be produced and kept at
the time and place of the meeting during the whole time thereof, and may be
inspected by any stockholder who is present.
Section 10. Consent of Stockholders in Lieu of Meeting. Whenever the
vote of stockholders at a meeting thereof is required or permitted to be taken
for or in connection with any corporate action, the meeting and vote of
stockholders can be dispensed with: (1) if all of the stockholders who would
have been entitled to vote upon the action if such meeting were held shall
consent in writing to such corporate action being taken; or (2) unless the
Certificate of Incorporation provides otherwise, with the written consent of
the holders of not less than the minimum percentage of the total vote required
by statue for the proposed corporate action, and provided that prompt notice
must be given to all stockholders of the taking of corporate action without
a meeting.
ARTICLE II
BOARD OF DIRECTORS
Section 1. General Powers. The business and affairs of the Corporation
shall be managed by the Board. The Board may exercise all such authority and
powers of the Corporation and do all such lawful acts and things as are not
by statute or the Certificate of Incorporation directed or required to be
exercised or done by the stockholders.
Section 2. (a) Number, Qualifications, Election and Term of Office. The
business and affairs of the Corporation shall be managed and controlled by a
Board of Directors consisting of fourteen (14) persons. At the 1989 Annual
Meeting of Stockholders, the directors were divided into three classes, as
nearly equal in number as possible, with the term of office of the first class
to expire at the 1990 Annual Meeting of Stockholders, the term of office of
the second class to expire at the 1991 Annual Meeting of Stockholders and the
term of office of the third class to expire at the 1992 Annual Meeting of
Stockholders. At each Annual Meeting of Stockholders following such initial
classification and election, directors elected to succeed those directors
whose terms expire shall be elected for a term of office to expire at the
third succeeding Annual Meeting of Stockholders after their election. All
directors shall be the age of majority and need not be stockholders. Each
director shall hold office until the end of his term and until his successor
shall have been duly elected and qualified, or until his death, or until he
shall have resigned, or have been removed for cause, as hereinafter provided
in these By-Laws or as otherwise provided by statute or the Certificate of
Incorporation.
(b) Filling of Vacancies. Except as otherwise provided in Article II,
Section 11, any vacancies on the Board resulting from death, resignation,
retirement, disqualification, removal from office or other cause shall be
filled by a majority vote of the directors then in office, and directors so
chosen shall hold office for a term expiring at the Annual Meeting of
Stockholders at which the term of the class to which they have been elected
expires. No decrease in the number of directors constituting the Board shall
shorten the term of any incumbent director.
(c) Removal. Any director, or the entire Board, may be removed from
office at any time, but only for cause and only by the affirmative vote of a
majority of the Board or the holders of at least sixty six and two thirds
percent (66 2/3%) of the voting power of all of the shares of the Corporation
entitled to vote for the election of directors. For the purposes of this
Paragraph (c), "cause" shall mean the willful and continuous failure of a
director substantially to perform such director's duties to the Corporation
(other than such failure resulting from incapacity due to physical or mental
illness) or the willful engaging by a director in gross misconduct materially
and demonstrably injurious to the Corporation.
Section 3. Place of Meetings. Meetings of the Board may be held at such
place, within or without the State of Delaware, as the Board may from time to
time determine or as shall be specified in the notice or waiver of notice of
such meeting.
Section 4. First Meeting. The Board shall meet for the purpose of
organization, the election of officers, and the transaction of other business,
as soon as practicable after each Annual Meeting of Stockholders, on the same
day and at the same place where such annual meeting shall be held. Notice of
such meeting need not be given. Such meeting may be held at any other time
or place (within or without the State of Delaware) which shall be specified
in a notice thereof given as hereinafter provided in Article II, Section 7.
Section 5. Regular Meetings. Regular meetings of the Board shall be held
at such time and place as the Board may from time to time determine. If any
day fixed for a regular meeting shall be a legal holiday at the place where
the meeting is to be held, then the meeting which would otherwise be held on
that day shall be held at the same hour on the next succeeding business day.
Notice of regular meetings of the Board need not be given except as otherwise
required by statute or these By-Laws.
Section 6. Special Meetings. Special meetings of the Board may be called
by two or more directors of the Corporation or by the Chairman of the Board
or the President.
Section 7. Notice of Meetings. Notice of each special meeting of the
Board (and of each regular meeting for which notice shall be required) shall
be given by the Secretary as hereinafter provided in this Section 7, in which
notice shall be stated the time and place (within or without the State of
Delaware) of the meeting. Notice of each such meeting shall be delivered to
each director either personally or by telephone, facsimile, telegraph, cable
or wireless, at least twenty-four hours before the time at which such meeting
is to be held or by first-class mail, postage pre-paid, addressed to him at
his residence, or usual place of business, at least three days before the day
on which such meeting is to be held. Notice of any such meeting need not be
given to any director who shall, either before or after the meeting, submit
a signed waiver of notice or who shall attend such meeting without protesting,
prior to or at its commencement, the lack of notice to him. Except as
otherwise specifically required by these By-Laws, a notice or waiver of notice
of any regular or special meeting need not state the purposes of such meeting.
Section 8. Quorum and Manner of Acting. Three directors or one-third of
the entire Board, whichever is greater, shall be present in person at any
meeting of the Board in order to constitute a quorum for the transaction of
business at such meeting, and, except as otherwise expressly required by
statute or the Certificate of Incorporation, the act of a majority of the
directors present at any meeting at which a quorum is present shall be the act
of the Board. In the absence of a quorum at any meeting of the Board, a
majority of the directors present thereat, or if no director be present, the
Secretary may adjourn such meeting to another time and place, or such meeting,
unless it be the first meeting of the Board, need not be held. At any
adjourned meeting at which a quorum is present, any business may be transacted
which might have been transacted at the meeting as originally called. Except
as provided in Article III of these By-Laws, the directors shall act only as
a Board and the individual directors shall have no power as such.
Section 9. Organization. At each meeting of the Board, the Chairman of
the Board (or, in his absence or inability to act, or, with respect to any
particular items which the President wishes the Board to consider, the
President, or in his absence or inability to act, another director chosen by
a majority of the directors present) shall act as chairman of the meeting and
preside thereat. The Secretary (or, in his absence or inability to act, any
person appointed by the chairman) shall act as secretary of the meeting and
keep the minutes thereof.
Section 10. Resignation. Any director of the Corporation may resign at
any time by giving written notice of his resignation to the Board of Chairman
of the Board or the President or the Secretary. Any such resignation shall
take effect at the time specified therein or, if the time when it shall become
effective shall not be specified therein, immediately upon its acceptance.
Unless otherwise specified therein, the acceptance of such resignation shall
not be necessary to make it effective.
Section 11. Certain Vacancies. Vacancies and newly created directorships
resulting from any increase in the authorized number of directors may be
filled by a majority of the directors then in office, though less than a
quorum, or by a sole remaining director, and the directors so chosen shall
hold office until the next annual election and until their successors are duly
elected and shall qualify, unless sooner displaced. If there are no directors
in office, then an election of directors may be held in the manner provided
by statute. If, at the time of filling any vacancy or any newly created
directorship, the directors then in office shall constitute less than a
majority of the whole board (as constituted immediately prior to any such
increase), the Court of Chancery may, upon application of any stockholder or
stockholders holding at least ten percent of the total number of the shares
at the time outstanding having the right to vote for such directors,
summarily order an election to be held to fill any such vacancies or newly
created directorships, or to replace the directors chosen by the directors
then in office. When one or more directors shall resign from the Board,
effective at a future date, a majority of the directors then in office,
including those who have so resigned, shall have power to fill such vacancy
or vacancies, the vote thereon to take effect when such resignation or
resignations shall become effective, and each director so chosen shall hold
office as provided in this action in the filling of other vacancies.
Section 12. Compensation. The Board shall have authority to fix the
compensation, including fees and reimbursement of expenses, of directors for
services to the Corporation in any capacity, provided no such payment shall
preclude any director from serving the Corporation in any other capacity and
receiving compensation therefor.
Section 13. Action Without Meeting. Any action required or permitted to
be taken at any meeting of the Board or of any committee thereof may be taken
without a meeting if all members of the Board or committee, as the case may
be, consent thereto in writing, and the writing or writings are filed with the
minutes of proceedings of the Board or committee.
Section 14. Telephonic Meetings. Unless otherwise restricted by the
Certificate of Incorporation or by these By-Laws, members of the Board of
Directors may participate in a meeting of the Board of Directors, or any
committee, by means of conference telephone or similar communications
equipment by means of which all persons participating in the meeting can hear
each other and such participation in a meeting shall constitute presence in
person at the meeting.
ARTICLE III
EXECUTIVE AND OTHER COMMITTEES
Section 1. Executive and Other Committees. The Board may, by resolution
passed by a majority of the whole Board, designate one or more committees,
each committee to consist of two or more of the directors of the Corporation.
The Executive Committee shall consist of the President and such of the other
members of the Board as shall be appointed pursuant to the immediately
preceding sentence. The Board may designate one or more directors as
alternate members of any committee, who may replace any absent or disqualified
member at any meeting of the committee. Any such committee, to the extent
provided in the resolution creating the committee, shall have and may exercise
the powers of the Board in the management of the business and affairs of the
Corporation, and may authorize the seal of the Corporation to be affixed to
all papers which may require it; provided, however, that in the absence or
disqualification of any member of such committee or committees, the member or
members thereof present at any meeting and not disqualified from voting,
whether or not he, she or they constitute a quorum, may unanimously appoint
another member of the Board to act at the meeting in the place of any such
absent or disqualified member. Each committee shall keep written minutes of
its proceedings and shall report such minutes to the Board when required. All
such proceedings shall be subject to revision or alteration by the Board;
provided, however, that third parties shall not be prejudiced by such revision
or alteration.
Section 2. General. A majority of any committee may determine its action
and fix the time and place of its meetings, unless the Board shall otherwise
provide. Notice of such meetings shall be given to each member of the
committee in the manner provided for in Article II, Section 7. The Board
shall have any power at any time to fill vacancies in, to change the
membership of, or to dissolve any such committee. Nothing herein shall be
deemed to prevent the Board from appointing one or more committees consisting
in whole or in part of persons who are not directors of the Corporation;
provided, however, that no such committee shall have or may exercise any
authority of the Board.
ARTICLE IV
OFFICERS
Section 1. Number and Qualifications. The officers of the Corporation
shall include the Chairman of the Board, the Vice- Chairman of the Board, the
President, one or more Vice-Presidents (any of whom may be designated as
Executive Vice-President), the Chief Financial Officer, the Treasurer, the
Controller and the Secretary. Any two or more offices may be held by the same
person. Such officers shall be elected from time to time by the Board or by
the President, each to hold office until his successor shall have been duly
elected or appointed and shall have qualified, or until his death, or until
he shall have resigned, or have been removed, as hereinafter provided in these
By-Laws. The Board may from time to time elect, or the President may appoint,
such other officers (including one or more Assistant Vice-Presidents,
Assistant Secretaries and Assistant Treasurers), and such agents as may be
necessary or desirable for the business of the Corporation. Such other
officers and agents shall have duties and shall hold their offices for such
terms as may be prescribed by the Board or by the appointing authority.
Section 2. Resignations. Any officer of the Corporation may resign at
any time by giving written notice of his resignation to the Board, the
Chairman of the Board, the President or the Secretary. Any such resignation
shall take effect at the time specified therein or, if the time when it shall
become effective shall not be specified therein, immediately upon its receipt;
and, unless otherwise specified therein, the acceptance of such resignation
shall not be necessary to make it effective.
Section 3. Removal. Any officer or agent of the Corporation may be
removed, either with or without cause, at any time, by the vote of the
majority of the entire Board at any meeting of the Board or, (except for the
Chairman of the Board) by the President. Such removal shall be without
prejudice to the contractual rights, if any, of the person so removed.
Section 4. Vacancies. A vacancy in any office, whether arising from
death, resignation, removal or any other cause, may be filled for the
unexpired portion of the term of the office which shall be vacant, in the
manner prescribed in these By-Laws for the regular elections or appointment
to such office.
Section 5. The Chairman of the Board. The Chairman of the Board shall,
if present, preside at each meeting of the stockholders and of the Board and
shall be an ex officio member of all committees of the Board. He shall
consult with and advise the President and Chief Executive Officer regarding
significant decisions and strategic options for the Company and he shall
perform all duties incident to the office of Chairman of the Board and such
other duties as may from time to time be assigned to him by the Board.
Section 6. Vice-Chairman of the Board. The Vice-Chairman of the Board
shall be responsible for assisting the Chairman of the Board and shall perform
all such duties as may from time to time be assigned to him by the Board.
Section 7. The President. The President shall be the Chief Executive
Officer of the Corporation and shall have general and active management of the
business of the Corporation and general and active supervision and direction
over the affairs of the Corporation and over all of its other officers, agents
and employees (except the Chairman of the Board) and shall see that their
duties are properly performed and their responsibilities properly discharged.
The President shall report directly to the Chairman of the Board and shall
consult with the Chairman of the Board regarding significant decisions and
strategic options for the Company. At the request of the Chairman of the
Board, or in the case of his absence or inability to act, the President shall
perform the duties of the Chairman of the Board and when so acting shall have
all the powers of, and be subject to, all the restrictions upon, the Chairman
of the Board. He shall perform all duties incident to the office of President
and such other duties as from time to time may be assigned to him by the
Board, and by these By-Laws.
Section 8. Vice Presidents. The Executive Vice-President and each Vice-
President shall have such powers and perform all such duties as from time to
time may be assigned to him by the Board or by the President.
Section 9. The Chief Financial Officer. The Chief Financial Officer
shall:
(a) have charge and custody of, and be responsible for, all
the funds and securities of the Corporation;
(b) keep full and accurate accounts of receipts and
disbursements in books belonging to the Corporation and have control of all
books of account of the Corporation;
(c) cause all moneys and other valuables to be deposited to
the credit of the Corporation in such depositaries as may be designated by the
Board;
(d) receive, and give receipts for, moneys due and payable to
the Corporation from any source whatsoever;
(e) disburse the funds of the Corporation and supervise the
investment of its funds as ordered or authorized by the Board, taking proper
vouchers therefor;
(f) render the Chairman of the Board, the President and the
Board, whenever the Board may require, an account of the financial condition
of the Corporation; and
(g) in general, perform all the duties incident to the office
of treasurer and such other duties as from time to time may be assigned to him
by the Board or by the President.
Section 10. The Secretary. The secretary shall:
(a) keep or cause to be kept in one or more books provided
for the purpose, the minutes of all meetings of the Board, the committees of
the Board and the stockholders;
(b) see that all notices are duly given in accordance with
the provisions of these By-Laws and as required by law;
(c) be custodian of the records and the seal of the
Corporation and affix and attest the seal to all stock certificates of the
Corporation (unless the seal of the Corporation on such certificates shall be
a facsimile, as hereinafter provided) and affix and attest the seal to all
other documents to be executed on behalf of the Corporation under its seal;
(d) see that the books, reports, statements, certificates and
other documents and records required by law to be kept and filed are properly
kept and filed; and
(e) in general, perform all the duties incident to the office
of Secretary and such other duties as from time to time may be assigned to him
by the Board or by the President.
Section 11. Officers' Bonds or Other Security. If required by the Board,
any officer of the Corporation shall give a bond or other security for the
faithful performance of his duties, in such amount and with such surety or
sureties as the Board may require.
Section 12. Compensation. The compensation of the officers of the
Corporation for their services as such officers shall be fixed from time to
time by the Board; provided, however, that the Board may delegate to the
President the power to fix the compensation of officers and agents appointed
by the President. An officer of the Corporation shall not be prevented from
receiving compensation by reason of the fact that he is also a director of the
Corporation, but any such officer who shall also be a director shall not have
any vote in the determination of the amount of compensation paid to him.
ARTICLE V
INDEMNIFICATION
Section 1. Right to Indemnification. The Corporation shall indemnify and
hold harmless, to the fullest extent permitted by applicable law as it
presently exists or may hereafter be amended, any person who was or is made
or is threatened to be made a party or is otherwise involved in any action,
suit or proceeding, whether civil, criminal, administrative or investigative
(a "proceeding"), by reason of the fact that he, or a person for whom he is
the legal representative, is or was a director or officer of the Corporation
or is or was serving at the request of the Corporation as a director, officer,
employee, fiduciary or agent of another corporation or of a partnership, joint
venture, trust, enterprise or nonprofit entity, including service with respect
to employee benefit plans, against all liability and loss suffered and
expenses reasonably incurred by such person. The Corporation shall indemnify
a person in connection with a proceeding initiated by such person only if the
proceeding was authorized by the Board.
Section 2. Prepayment of Expenses. The Corporation shall pay the
expenses incurred in defending any proceeding in advance of its final
disposition; provided, however, that the payment of expenses incurred by a
director or officer in his capacity as a director or officer in advance of the
final disposition of the proceeding shall be made only upon receipt of an
undertaking by the director or
officer to repay all amounts advanced if it should be determined to be
indemnified under this Article V or otherwise.
Section 3. Claims. If a claim for indemnification or payment of expenses
under this Article V is not paid in full within ninety days after a written
claim therefor has been received by the Corporation, the claimant may file
suit to recover the unpaid amount of such claim and, if successful in whole
or in part, shall be entitled to be paid the expense of prosecuting such
claim. In any such action, the Corporation shall have the burden of proving
that the claimant was not entitled to the requested indemnification or payment
of expenses under applicable law.
Section 4. Nonexclusivity of Rights. The rights conferred on any person
by this Article V shall not be exclusive of any other rights which such person
may have or hereafter acquire under any statute, provision of the Certificate
of Incorporation, these By-
Laws, agreement, vote of stockholders or disinterested directors or otherwise.
Section 5. Contracts and Arrangements. The Corporation may enter into
contracts providing indemnification to the full extent authorized or permitted
by the Delaware General Corporation Law and may create a trust fund, grant a
security interest and/or use other means (including, without limitation,
letters of credit, surety bonds and other similar arrangements) to ensure the
payment of such amounts as may become necessary to effect indemnification
pursuant to such contracts or otherwise.
Section 6. Amendment or Repeal. Any repeal or modification of the
foregoing provisions of this Article V shall not adversely affect any right
or protection of any person in respect of any act or omission occurring prior
to the time of such repeal or modification.
ARTICLE VI
CONTRACTS, CHECKS, DRAFTS, BANK ACCOUNTS, ETC.
Section 1. Execution of Contracts. Except as otherwise required by
statute, the Certificate of Incorporation or these By-Laws, any contracts or
other instruments may be executed and delivered in the name and on behalf of
the Corporation by such officer or officers (including any assistant officer)
of the Corporation as the Board may from time to time direct. Such authority
may be general or confined to specific instances as the Board may determine.
Unless authorized by the Board or expressly permitted by these By-Laws, an
officer or agent or employee shall not have any power or authority to bind the
Corporation by any contract or engagement or to pledge its credit or to render
it pecuniarily liable for any purpose or to any amount.
Section 2. Loans. Unless the Board shall otherwise determine, either (a)
the President, or (b) any Vice President, the Chief Financial Officer, the
Treasurer or the Secretary, together with the President, may effect loans and
advances at any time for the Corporation from any bank, trust company or other
institution, or from any firm, corporation or individual, and for such loans
and advances may make, execute and deliver promissory notes, bonds or other
certificates or evidence of indebtedness of the Corporation, but no officer
or officers shall mortgage, pledge, hypothecate or transfer any securities or
other property of the Corporation, except when authorized by the Board.
Section 3. Checks, Drafts, etc. All checks, drafts, bills of exchange or
other orders for the payment of money out of the funds of the Corporation, and
all notes or other evidences of indebtedness of the Corporation, shall be
signed in the name and on behalf of the Corporation by such persons and in
such manner as shall from time to time be authorized by the Board.
Section 4. Deposits. All funds of the Corporation not otherwise employed
shall be deposited from time to time to the credit of the Corporation in such
banks, trust companies or other depositories as the Board may from time to
time designate or as may be designated by any officer or officers of the
Corporation to whom such power of designation may from time to time be
delegated by the Board. For the purpose of deposit and for the purpose of
collection for the account of the Corporation, checks, drafts and other orders
for the payment of money which are payable to the order of the Corporation may
be endorsed, assigned and delivered by any officer or agent of the
Corporation, or in such manner as the Board may determine by resolution.
Section 5. General and Special Bank Accounts. The Board may from time to
time authorize the opening and keeping of general and special bank accounts
with such banks, trust companies or other depositories as the Board may
designate or as may be designated by any officer or officers of the
Corporation to whom such power of designation may from time to time be
delegated by the Board. The Board may make such special rules and regulations
with respect to such bank accounts, not inconsistent with the provisions of
these By-Laws, as it may deem expedient.
Section 6. Proxies in Respect of Securities of Other Corporations.
Unless otherwise provided by resolution adopted by the Board, the President
or a Vice President may from time to time appoint an attorney or attorneys or
agent or agents, of the Corporation, in the name and on behalf of the
Corporation to cast the votes which the Corporation may be entitled to cast
as the holder of stock or other securities in any other corporation, any of
the stock or other securities of which may be held by the Corporation, at
meetings of the holders of the stock or other securities of such other
corporation, or to consent in writing, in the name of the Corporation as such
holder, to any action by such other corporation, and may instruct the person
or persons so appointed as to the manner of casting such votes or giving such
consent, and may execute or cause to be executed in the name and on behalf of
the Corporation and under its corporate seal, or otherwise, all such written
proxies or other instruments as he may deem necessary or proper.
ARTICLE VII
SHARES, ETC.
Section 1. Stock Certificates. Each holder of stock of the Corporation
shall be entitled to have a certificate, in such form as shall be approved by
the Board, certifying the number of shares of stock of the Corporation owned
by him. The certificates representing shares of stock shall be signed in the
name of the Corporation by the Chairman of the Board or the President or a
Vice-President and by the Secretary or an Assistant Secretary or the Treasurer
or an Assistant Treasurer and sealed with the seal of the Corporation (which
seal may be a facsimile, engraved or printed); provided, however, that where
any such certificate is countersigned by a transfer agent other than the
Corporation or its employee, or is registered by a registrar other than the
Corporation or one of its employees, the signature of the officers of the
Corporation upon such certificates may be facsimiles, engraved or printed.
In case any officer who shall have signed or whose facsimile signature has
been placed upon such certificates shall have ceased to be such officer before
such certificates shall be issued, they may nevertheless be issued by the
Corporation with the same effect as if such officer were still in office at
the date of their issue.
Section 2. Books of Account and Record of Stockholders. The books and
records of the Corporation may be kept at such places within or without the
State of Delaware, as the Board may from time to time determine. The stock
record books and the blank stock certificate books shall be kept by the
Secretary or by any other officer or agent designated by the Board.
Section 3. Transfers of Shares. Transfers of shares of stock of the
Corporation shall be made on the stock records of the Corporation only upon
authorization by the registered holder thereof, or by his attorney thereunto
authorized by power of attorney duly executed and filed with the Secretary or
with a transfer agent or transfer clerk, and on surrender of the certificate
or certificates for such shares properly endorsed or accompanied by a duly
executed stock transfer power and the payment of all taxes thereon. Except
as otherwise provided by law, the Corporation shall be entitled to recognize
the exclusive right of a person in whose name any share or shares stand on the
record of stockholders as the owner of such share or shares for all purposes,
including, without limitation, the rights to receive dividends or other
distributions, and to vote as such owner, and the Corporation may hold any
such stockholder of record liable for calls and assessments and the
Corporation shall not be bound to recognize any equitable or legal claim to
or interest in any such share or shares on the part of any other person
whether or not it shall have express or other notice thereof. Whenever any
transfers of shares shall be made for collateral security and not absolutely,
and both the transferor and transferee request the Corporation to do so, such
fact shall be stated in the entry of the transfer.
Section 4. Regulations. The Board may make such additional rules and
regulations, not inconsistent with these By-Laws, as it may deem expedient
concerning the issue, transfer and registration of certificates for shares
of stock of the Corporation. It may appoint, or authorize any officer or
officers to appoint, one or more transfer agents or one or more transfer
clerks and one or more registrars and may require all certificates for shares
of stock to bear the signature or signatures of any of them.
Section 5. Lost, Destroyed or Mutilated Certificates. The holder of any
certificate representing shares of stock of the Corporation shall immediately
notify the Corporation of any loss, destruction or mutilation of such
certificate, and the Corporation may issue a new certificate of stock in the
place of any certificate theretofore issued by it which the owner thereof
shall allege to have been lost, stolen or destroyed, or which shall have been
mutilated, and the Board may, in its discretion, require such owner or his
legal representative to give to the Corporation a bond in such sum, limited
or unlimited, and in such form and with such surety or sureties as the Board
in its absolute discretion shall determine, to indemnify the Corporation
against any claim that may be made against it on account of the alleged loss,
theft, or destruction of any such certificate, or the issuance of a new
certificate. Anything herein to the contrary notwithstanding, the Board, in
its absolute discretion, may refuse to issue any such new certificate, except
pursuant to legal proceedings under the laws of the State of Delaware.
Section 6. Stockholder's Right of Inspection. Any person who shall have
been a stockholder of record of the Corporation for at least six months
immediately preceding his demand, or any person holding, or thereunto
authorized by the holders of, at least five percent of the outstanding shares
of stock of the Corporation, shall, in person or by attorney or other agent,
upon written demand under oath stating the purpose thereof, have the right
during the ordinary business hours to inspect for any proper purpose the
Corporation's stock ledger, a list of its stockholders and its other books and
records, and to make copies or extracts therefrom. A proper purpose shall
mean a purpose reasonably related to such person's interest as a stockholder.
In every instance where an attorney or other agent shall be the person who
seeks the right to inspection, the demand under oath shall be accompanied by
a power of attorney or such other writing which authorizes the attorney or
other agent to so act on behalf of the stockholder. The demand under oath
shall be directed to the Corporation at its registered office in this State
or at its principal place of business.
Section 7. Fixing of Record Date. In order that the Corporation may
determine the stockholders entitled to notice of or to vote at the meeting of
stockholders or any adjournment thereof, or to express consent to corporate
action in writing without a meeting, or entitled to receive payment of any
dividend or other distribution or allotment of any rights or entitled to
exercise any rights in respect of any change, conversion or exchange of stock
or for the purpose of any other lawful action, the Board may fix, in advance,
a record date, which shall not be more than sixty nor less than ten days
before the date of such meeting, nor more than sixty days prior to any other
action. A determination of stockholders of record entitled to notice of or
to vote at a meeting of stockholders shall apply to any adjournment of the
meeting; provided, however, that the Board may fix a new record date for the
adjourned meeting.
ARTICLE VIII
OFFICES
Section 1. Registered Office. The registered office of the Corporation
in the State of Delaware shall be at 1209 Orange Street, Wilmington, County
of New Castle, Delaware. The name of the resident agent in charge thereof
shall be the Corporation Trust Company.
Section 2. Other Offices. The Corporation may also have an office or
offices other than said principal office at such place or places, either
within or without the Sate of Delaware, as the Board shall from time to time
determine or the business of the Corporation may require.
ARTICLE IX
FISCAL YEAR
The fiscal year of the Corporation shall be January 1 to December 31 of
each year.
ARTICLE X
SEAL
The Board shall provide a corporate seal, which shall be in the form of
two concentric circles and bear the name of the Corporation and the words and
figures "Corporate Seal 1971 Delaware."
ARTICLE XI
AMENDMENTS
The Board shall have the power to amend these By-Laws by a majority vote.
Notwithstanding anything contained in these By-Laws to the contrary, the
stockholders may amend these By-Laws, but only by an affirmative vote of
sixty-six and two-thirds percent (66 2/3%) of the voting power of all shares
of the Corporation entitled to vote, except when stockholders are required to
vote by class, in which event sixty-six and two-thirds percent (66 2/3%) of
the voting power of that class shall be required.
Exhibit 4.1
Specimen Copy of Form of Common Stock Certificate
The following is the text of the Company's new specimen
Common Stock Certificate:
COMMON STOCK COMMON STOCK
INCORPORATED UNDER THE LAWS CUSIP 130190 10 1
OF THE STATE OF DELAWARE SEE REVERSE FOR CERTAIN DEFINITIONS
COMMON STOCK, PAR VALUE $0.0675
This certificate is transferable
in San Francisco or in
the City of New York
CALIFORNIA ENERGY COMPANY, INC.
This certifies that
is the registered owner of
FULLY PAID AND NON-ASSESSABLE SHARES OF COMMON STOCK, PAR
VALUE $0.0675 PER SHARE, OF California Energy Company, Inc.
(the "Corporation"), transferable on the books of the
Corporation by the holder hereof in person or by duly
authorized attorney upon the surrender of this certificate
properly endorsed. This certificate and the shares
represented hereby are issued and shall be held subject to all
of the provisions of the Certificate of Incorporation and
Bylaws of the Corporation, to all of which the holder of this
certificate assents by acceptance hereof.
Reference is made to the statements on the reverse hereof
with respect to certain rights represented hereby and
concerning classes and series of the Corporation's shares.
This certificate is not valid until countersigned and
registered by the Transfer Agent and Registrar.
Witness the facsimile seal of the Corporation and the
facsimile signatures of the duly authorized officers.
DATED:
COUNTERSIGNED AND REGISTERED:
CHEMICAL TRUST COMPANY OF CALIFORNIA
TRANSFER AGENT AND REGISTRAR,
BY:
[FRONT]
[BACK]
CALIFORNIA ENERGY COMPANY, INC.
This certificate also represents and entitles the holder
hereof to certain rights as set forth in a Rights Agreement
between California Energy Company, Inc. and Chemical Trust
Company of California dated as of December 1, 1988, as amended
(the "Rights Agreement"), the terms of which are hereby
incorporated herein by reference and a coy of which is on file
at the principal executive offices of California Energy
Company, Inc. in Omaha, Nebraska. Under certain
circumstances, as set forth in the Rights Agreement, such
Rights will be represented by separate certificates and will
no longer be evidenced by this certificate. California Energy
Company, Inc. will mail to the holder of this certificate a
copy of the Rights Agreement without charge after receipt of a
written request therefor. As described in the Rights
Agreement, Rights issued to Acquiring Persons (as defined in
the Rights Agreement) shall be and become null and void.
California Energy Company, Inc. is authorized to issue two
classes of shares, Common and Preferred, and the Preferred may
be issued in two or more series. A statement of the rights,
preferences, privileges and restrictions granted to or imposed
upon the respective classes or series of shares and upon the
holders thereof as established by the Certificate of
Incorporation or by any Certificate of Determination of
Preferences, and the number of shares constituting each series
and designations thereof, may be obtained upon written request
and without charge from the aforesaid principal office of the
Corporation. The Board of Directors of the Corporation has
authority to fix any or all of dividend rights, dividend rate,
conversion rights, voting rights, rights of redemption
(including sinking fund provisions), the redemption price and
liquidation preference of any wholly unissued Preferred Shares
or of any wholly unissued series of Preferred Shares, the
number of shares constituting any unissued series of Preferred
Shares, and the designations of such series.
The following abbreviations, when used in the inscription on
the face of this certificate, shall be construed as through
they were written out in full according to applicable laws or
regulations:
TEN COM - as tenants in common
TEN ENT - as tenants by the entireties
JT TEN - as joint tenants with right of survivorship and
not as tenants in common
UNIF GIFT MIN ACT - _______ Custodian _______
(Cust) (Minor)
under Uniform Gifts to Minors
Act _______________________
(State)
UNIF TRAN MIN ACT - _______ Custodian _______
(Cust) (Minor)
under Uniform Transfers to Minors
Act _______________________
(State)
Additional abbreviations may also be used though not in the
above list.
For Value Received, _______________ hereby sell, assign and
transfer unto
PLEASE INSERT SOCIAL SECURITY OR OTHER IDENTIFYING NUMBER OF
ASSIGNEE
______________________________
______________________________________________________________
(please print or typewrite name and address, including zip
code, of assignee)
______________________________________________________________
______________________________________________________________
______________________________________________________________ Shares
of the capital stock represented by the within Certificate,
and do hereby irrevocably constitute and appoint
______________________________________________________________ Attorney
to transfer the said stock on the books of the within named
Corporation and full power of substitution in the premises.
Dated___________________________________________
Signatures(s) Guaranteed:
By
THE SIGNATURE(S) SHOULD BE GUARANTEED BY AN ELIGIBLE GUARANTOR
INSTITUTION, (BANKS, STOCKBROKERS, SAVINGS AND LOAN
ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED
SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C RULE
17Ad-15.
DEFEASANCE AGREEMENT
DEFEASANCE AGREEMENT, dated as of March 3, 1994 (this "Agreement"), by
and among California Energy Company, Inc. (the "Company") and Principal
Mutual Life Insurance Company ("Principal Mutual").
PRELIMINARY STATEMENT. The Company and Principal Mutual are parties to
a Note Purchase Agreement, dated as of March 15, 1988 (the "Purchase
Agreement"), pursuant to which the Company issued and sold to Principal
Mutual $30,000,000 in aggregate principal amount of the Company's 12%
Senior Notes with Contingent Interest due 1995 (the "Notes"). The Company
proposes to enter into an Escrow Deposit Agreement (the "Escrow Agreement")
in substantially the form attached hereto as Exhibit A with Bank of America
National Trust and Savings Association (the "Trustee"), pursuant to which,
among other things, the Company will deposit certain funds and/or
securities sufficient to provide for the payment of principal and interest
(excluding Contingent Interest) on the Notes on each date when any amount
thereof is to become due and payable. Capitalized terms used herein and
not otherwise defined shall have the meanings assigned to such terms in the
Purchase Agreement.
In consideration of the foregoing and other good and valuable
consideration, the Company and Principal Mutual agree as follows:
1. Upon the satisfaction of the conditions set forth in
Paragraph 2 hereof on a date subsequent to March 15, 1994, the Company
shall be released from its obligations to comply with any covenant
contained in 8.3-8.15, 8.16(a), 8.17-8.19 and 8.21 (the "Defeased
Covenants") of the Purchase Agreement and the outstanding Notes shall
thereafter be deemed not to be "outstanding" for the purposes of any
direction, waiver, consent or declaration or action by the Noteholders (and
the consequences thereof) in connection with the Defeased Covenants, but
shall continue to be deemed "outstanding" for all other purposes under the
Purchase Agreement (it being understood that the Notes shall not be deemed
outstanding for financial accounting purposes), with the effect that the
Company may omit to comply with and shall have no liability in respect of
any term condition or limitation set forth in any of the Defeased
Covenants, whether directly or indirectly, by reason of any reference
elsewhere in the Purchase Agreement or the Notes to any such covenant and
such omission to comply shall not constitute a Default or Event of Default
under 10.1 of the Purchase Agreement, but, except as specified above and
in the next sentence, the remainder of the Purchase Agreement and the Notes
shall be unaffected thereby. In addition, upon the satisfaction of the
conditions set forth in Paragraph 2 hereof, the occurrence of an event
referred to in 10.1(f) or (n) shall not constitute Event of Default.
2. The following shall be the conditions to the defeasance
provided under this Agreement:
(a) The Company shall have deposited or caused to be deposited
with the Trustee pursuant to the Escrow Agreement as trust funds in trust
for the purpose of making the following payments, specifically and
irrevocably pledged as security for and dedicated solely to, the benefit of
the Noteholders, the securities identified in Exhibit B to the Escrow
Agreement.
(b) No Default or Event of Default shall have occurred and be
continuing on the date of such deposit.
(c) The Company shall not be "insolvent" within the meaning of
any applicable law on the date of such deposit.
(d) The defeasance provided under Paragraph 1 hereof shall not
constitute or result in a breach or violation, or constitute a default
under, any agreement or instrument to which the Company is a party or by
which it is bound and the Company shall have delivered to the Trustee and
to each holder of an Outstanding Note an Officer's Certificate to such
effect.
(e) The Company shall have delivered to the Trustee and to each
holder of an Outstanding Note an Officer's Certificate stating that (i) the
deposit made by the Company pursuant to subparagraph (a) of this Paragraph
2 was not made by the Company with the intent of preferring the Noteholders
over other creditors of the Company with the intent of defeating,
hindering, delaying or defrauding creditors of the Company and (ii) the
conditions set forth in subparagraph (c) of this Paragraph 2 have been
satisfied.
(f) The Company and the Trustee shall have executed and
delivered the Escrow Agreement.
3. If an Event of Default under any of 10.1(h) through
10.1(m) of the Purchase Agreement shall occur or if the Trustee (or any
paying agent) is unable to apply any money in accordance with the Escrow
Agreement, as the case may be, by reason of any order or judgment of any
court or governmental authority enjoining, restraining or otherwise
prohibiting such application, then the Company's obligations under the
Defeased Covenants shall be revived and reinstated as though no deposit had
occurred pursuant to Paragraph 1 hereof, until such time as the Trustee (or
paying agent) is permitted to apply all such money in accordance with
Paragraph 1 hereof and the Escrow Agreement; provided, however, that (i) if
the Company makes any payment of principal of or interest on any Note
following the reinstatement of its obligations, the Company shall be
subrogated to the rights of the holders of such Notes to receive such
payment from the money held by the Trustee (or paying agent) under the
Escrow Agreement and (ii) no action taken by the Company in reliance upon
such deposit and the inapplicability of the Defeased Covenants prior to any
such revival or reinstatement shall constitute or give rise to a Default or
Event of Default under the Purchase Agreement.
4. Until the Notes shall have been paid in full, the Company
agrees that it will not permit any Joint Venture to sell, transfer, lease
or otherwise dispose of any of its assets other than in the ordinary course
of business or in connection with any upgrade, replacement or retirement of
any equipment, and further agrees that any violation of the foregoing shall
constitute an Event of Default under the Purchase Agreement.
5. This Agreement is executed pursuant to 12.4 of the Purchase
Agreement and shall (unless otherwise expressly indicted herein) be
construed, administered, and applied in accordance with all of the terms
and provisions of the Purchase Agreement. Except as expressly released
hereby, all of the representations, warranties, terms, covenants and
conditions of the Purchase Agreement shall remain in effect. The
defeasance set forth herein shall be limited precisely as provided for
herein to the provisions expressly referred to herein and shall not be
deemed to be a waiver, release, amendment or modification of any other term
or provision of the Purchase Agreement or of any term or provision of any
other document or of any transaction or further action on the part of the
Company which would require the consent of any Noteholder under the
Purchase Agreement.
6. This Agreement may be executed simultaneously in two or
more counterparts, each of which shall be deemed to be an original but all
of which shall constitute together but one and the same instrument.
7. This Agreement shall be binding upon, and inure to the
benefit of, the parties hereto and their respective successors and assigns
(including, without limitation, any holder of the Notes whether or not such
holder shall have been expressly assigned any rights hereunder.
8. This Agreement shall be governed by and construed in
accordance with the law of the State of New York, including Section 5-1401
of the New York General Obligations Law, but otherwise without regard to
conflict of laws principles.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
executed by their respective officers duly authorized thereunto as of the
day and year first above written.
CALIFORNIA ENERGY COMPANY, INC.
By: /s/ John G. Sylvia
Name: John G. Sylvia
Title: Vice President &
Chief Financial Officer
PRINCIPAL MUTUAL LIFE INSURANCE COMPANY
By: /s/ Dennis D. Ballard, Counsel
Name: Dennis D. Ballard
Title: Counsel
By: /s/ Clint Woods
Name: Clint Woods
Title: Counsel
CONSENT AND AGREEMENT
This CONSENT AND AGREEMENT, dated March 24, 1994, of Principal
Mutual Life Insurance Company ("Principal Mutual").
WHEREAS, the undersigned, Principal Mutual, and California Energy
Company, Inc. (the "Company") are parties to a Defeasance Agreement, dated
as of March 3, 1994 (the "Defeasance Agreement"), pursuant to which, among
other things, the Company is expected to deposit certain funds and/or
securities sufficient to provide for the payment of principal and interest
(excluding Contingent Interest) on the Notes on each date when any amount
thereof is to become due and payable pursuant to the Escrow Agreement;
WHEREAS, immediately following the deposit by the Company of such
funds and/or securities with the Trustee pursuant to the Escrow Agreement
(the "Escrow Funding"), the Company is expected to issue its 10 - 1/4%
Senior Discount Notes due 2004 (the "Public Notes") in a principal amount
which is expected to provide gross proceeds of approximately $400,000,000
to the Company;
WHEREAS, Principal Mutual is the sole holder of all of the Notes;
and
WHEREAS, the Company has provided Principal Mutual with a copy of
the Final Prospectus, dated March 18, 1994 (the "Final Prospectus"),
relating to the Public Notes.
NOW, THEREFORE, in consideration of the foregoing and other good
and valuable consideration, Principal Mutual hereby agrees as follows:
1. Notwithstanding anything contained in the Purchase Agreement
or the Defeasance Agreement to the contrary, effective upon (x) the Escrow
Funding pursuant to subparagraph 2(a) of the Defeasance Agreement, (y) the
delivery to Principal Mutual of an Officer's Certificate stating that each
of the conditions set forth in subparagraphs 2(b) through (d) of the
Defeasance Agreement has been satisfied and (z) the satisfaction of
subparagraphs 2(e) and 2(f) of the Defeasance Agreement (the time upon
which all of such clauses (x), (y) and (z) have been first satisfied being
referred to herein as the "Effective Time"), Principal Mutual hereby
confirms that the Defeasance Agreement is effective and, subject to
paragraph 3 of the Defeasance Agreement, the defeasance of the Notes
thereunder is binding upon Principal Mutual and all subsequent holders of
Notes.
2. Notwithstanding anything contained in the Purchase Agreement
or the Defeasance Agreement to the contrary, effective from and after the
Effective Time, Principal Mutual hereby consents (on its own behalf and on
behalf of all future holders of Notes) to the issuance by the Company of
the Public Notes and the performance by the Company of its obligations
under the Public Notes and the related Indenture (all as more fully
described in the Final Prospectus).
3. Principal Mutual hereby agrees to take all such action as
the Company may reasonably request in order to ensure that future holders,
if any, of the Notes are aware of and bound by the terms and conditions of
the Defeasance Agreement and this Consent and Agreement.
Capitalized terms used herein and not otherwise defined herein
shall have the meanings assigned to such terms in the Defeasance Agreement
or the "Purchase Agreement" referenced therein.
IN WITNESS WHEREOF, Principal Mutual has caused this Consent and
Agreement to be executed by the respective officers duly authorized
thereunto as of the day and year first above written.
PRINCIPAL MUTUAL LIFE INSURANCE COMPANY
By: /s/Dennis Ballard
Name: Dennis Ballard, Counsel
By: /s/Clint Woods,
Name: Clint Woods, Counsel
EXHIBIT 4.7
ESCROW DEPOSIT AGREEMENT
Between
CALIFORNIA ENERGY COMPANY, INC.
And
BANK OF AMERICA NATIONAL TRUST AND SAVINGS
ASSOCIATION,
as Escrow Agent
Dated March 3, 1994
TABLE OF CONTENTS
Page
Recitals . . . . . . . . . . . 1
SECTION 1. Effectiveness of Agreement. . . . . . . . . . . . 2
SECTION 2. Appointment of the Escrow Agent . . . . . . . . . 3
SECTION 3. Escrow Account. . . . . . . . . . . . . . . . . . .3
SECTION 4. Deposit of Funds. . . . . . . . . . . . . . . . . .4
SECTION 5. Investment. . . . . . . . . . . . . . . . . . . . .4
SECTION 6. Deposit and Reinvestment of Funds . . . . . . . . .5
SECTION 7. Payments on Notes . . . . . . . . . . . . . . . . .5
SECTION 8. Irrevocable Deposit; Prior Charge Over Other
Charges and Claims; Relinquishment of Rights
of the Company . . . . . . . . . . . . . .6
SECTION 9. Liability of Escrow Agent . . . . . . . . . . . . .6
SECTION 10. Termination; Income From Government Obligations . .7
SECTION 11. Payment . . . . . . . . . . . . . . . . . . . . . .8
SECTION 12. Fees and Expenses . . . . . . . . . . . . . . . . .8
SECTION 13. Defeasance. . . . . . . . . . . . . . . . . . . . .9
SECTION 14. Benefit of Agreement; Amendments. . . . . . . . . .9
SECTION 15. Controversies . . . . . . . . . . . . . . . . . . 10
SECTION 16. Indemnification of Escrow Agent . . . . . . . . . 10
SECTION 17. Investment Instructions . . . . . . . . . . . . . 11
SECTION 18. Backup Withholding. . . . . . . . . . . . . . . . 12
SECTION 19. Resignation of Escrow Agent . . . . . . . . . . . 12
SECTION 20. Governing Law . . . . . . . . . . . . . . . . . . 13
SECTION 21. Counterparts. . . . . . . . . . . . . . . . . . . 13
SECTION 22. Section Headings. . . . . . . . . . . . . . . . . 13
Exhibit A Defeasance Agreement
Exhibit B Government Obligations
Exhibit C Defeasance Requirements
Exhibit D Fee Schedule
Exhibit E Form W-9
ESCROW DEPOSIT AGREEMENT
This Escrow Deposit Agreement (the "Agreement"), dated
March 3, 1994, between California Energy Company, Inc. (the "the Company")
and Bank of America National Trust and Savings Association, as Escrow
Agent, and as agent of the Company in connection with the purchase of
Government Obligations (defined herein) (the "Escrow Agent").
W I T N E S S E T H:
WHEREAS, the Company and Principal Mutual Life Insurance
Company(the "Lender") are parties to a Note Purchase Agreement, dated March
15, 1988, as amended to date (as so amended, the "Note Purchase
Agreement"), pursuant to which the Company originally issued and sold to
the Lender $30,000,000 aggregate principal amount of its 12% Senior Notes
with Contingent Interest due 1995 (the "Notes"), of which $35,730,480
aggregate principal amount is outstanding as of the date hereof (consisting
of $30,000,000 of original principal and $5,730,480 interest on the Notes
which accrued prior to September 15, 1989 and remains unpaid);
WHEREAS, the Notes provide for, among other things,
interest on the unpaid principal balance thereof at the rate of 12% per
annum (herein referred to as "Basic Interest") and certain additional
interest on the Notes defined therein (and referred to herein) as
"Contingent Interest";
WHEREAS, the Company plans to incur certain "Indebtedness
for Money Borrowed" (as defined in the Note Purchase Agreement) and utilize
the proceeds thereof in a manner that requires a waiver or the termination
of certain covenants under the Note Purchase Agreement, and the Lender, as
the holder of 100% of the Notes, has agreed to enter into a Defeasance
Agreement in the form attached as Exhibit A (the "Defeasance Agreement");
WHEREAS, in connection with its agreement to execute the
Defeasance Agreement, the Lender has required the Company to provide for
the payment of the principal, premium, if any, and Basic Interest on the
Notes by irrevocably depositing with the Escrow Agent an amount sufficient
to pay and discharge the entire indebtedness on the Notes for the principal
thereof on March 15, 1995 (the "Stated Maturity Date") and for Basic
Interest payable semiannually on each March 15 and September 15 after the
Effectiveness Date (hereinafter defined) to and including the Stated
Maturity Date, as set forth more fully on Exhibit C hereto (the aggregate
of such principal and Basic Interest payments being hereinafter referred to
as the "Defeasance Requirements"); and
WHEREAS, the Company wishes to enter into this Agreement
to carry out the foregoing purposes.
NOW, THEREFORE, in consideration of the foregoing and of
the mutual covenants herein set forth, the Company and the Escrow Agent
agree as follows:
SECTION 1. Effectiveness of Agreement. This Agreement
shall be and become effective only upon the date after March 15, 1994 (the
"Effectiveness Date"), if any, of delivery of, and payment for, the
Company's ___% Senior Discount Notes due 2004. The Company shall provide
the Escrow Agent with at least two business days' notice of the
Effectiveness Date. If the Effectiveness Date has not occurred on or prior
to June 30, 1994 (the "Early Termination Date"), then this Agreement shall
terminate on the Early Termination Date and be of no further force or
effect.
SECTION 2. Appointment of the Escrow Agent. The Company
hereby designates and appoints Bank of America National Trust and Savings
Association as Escrow Agent to serve in accordance with the terms,
conditions and provisions of this Agreement, and Bank of America National
Trust and Savings Association hereby agrees to act as Escrow Agent, upon
the terms, conditions and provisions set forth in this Agreement.
SECTION 3. Escrow Account. Upon the Effectiveness Date,
there is hereby established with the Escrow Agent a separate and
irrevocable account designated the "California Energy Escrow Account" (the
"Escrow Account") to be funded in the manner set forth in Section 4 below
and held in the custody of the Escrow Agent as a special escrow fund,
separate and apart from all other funds of the Company or the Escrow Agent,
for the benefit of the holder(s) of the Notes from time to time (the
"Holders"). All moneys and Government Obligations set aside and held in
trust in the Escrow Account shall be applied to, and applied solely for,
the payment of the Defeasance Requirements as the same shall become due and
payable as provided herein. The Company hereby grants to the Holders a
security interest in the Escrow Account and the Escrow Agent agrees to act
as the agent of the Holders in connection therewith.
SECTION 4. Deposit of Funds. On the Effectiveness Date,
the Company will irrevocably deposit with the Escrow Agent in the Escrow
Account an amount of cash and/or "Government Obligations" (defined below)
necessary to pay the Defeasance Requirements when due.
SECTION 5. Investment. (a) The Escrow Agent shall
invest the funds deposited in the Escrow Account only in those marketable
direct obligations issued by the United States of America backed by the
full faith and credit of the United States of America which are listed on
Exhibit B attached hereto (the "Government Obligations") or otherwise in
accordance with such joint written instructions as the Company and all of
the Holders may, from time to time, provide (all such investments, the
"Escrowed Securities"). The Escrow Agent shall hold the Escrowed Securities
and the proceeds, if any, thereof at all times in the Escrow Account,
wholly segregated from other funds and securities on deposit with the
Escrow Agent. The Escrow Agent shall not commingle amounts in the Escrow
Account with other funds or securities of the Escrow Agent or the Company
and shall hold and dispose of the assets therein only as set forth herein.
(b) The Government Obligations shall mature as to
principal and interest in such amounts and at such times as set forth in
Exhibit B so as to assure, together with the cash, if any, held in the
Escrow Account, the availability of sufficient moneys to satisfy the
Defeasance Requirements.
(c) Cash on deposit in the Escrow Account, not
otherwise invested in Government Obligations, shall be held in a U.S.
dollar denominated deposit account at the Escrow Agent, unless the Company
and all of the Holders provide the Escrow Agent with joint written
instructions specifying other permitted investments.
(d) The Company is the owner of the Escrowed Securities
and other assets held by the Escrow Agent pursuant to this Agreement for
federal, state and local income tax purposes and any income generated by
such investments and assets will be includable in the gross income of the
Company.
SECTION 6. Deposit and Reinvestment of Funds. The Escrow
Agent agrees and is authorized (a) to deposit in the Escrow Account upon
receipt, all principal and interest and other income on and proceeds of the
Escrowed Securities, and (b) to reinvest such principal and interest and
income and proceeds in Government Obligations in accordance with Section 5
hereof.
SECTION 7. Payments on Notes. On the Stated Maturity
Date and respective Basic Interest payment dates for the Notes, the Escrow
Agent shall apply sufficient moneys, to the extent available, from the
matured principal of and interest on the Government Obligations held in the
Escrow Account, or other moneys held in such Account, to the payment of the
principal of and Basic Interest accrued on the Notes, as the same shall
become due on such dates.
SECTION 8. Irrevocable Deposit; Prior Charge Over Other
Charges and Claims; Relinquishment of Rights of the Company. (a) The
deposit of the moneys and Government Obligations in the Escrow Account
shall constitute an irrevocable deposit in trust solely for the payment of
the Defeasance Requirements on the Notes, and solely for the benefit of the
Holders pursuant to the terms of this Agreement. The Holders shall have a
prior charge over all other charges or claims whatsoever against all moneys
and Government Obligations, including the proceeds thereof and the interest
and income earned thereon, on deposit in the Escrow Account, until said
moneys, Government Obligations, proceeds, interest and income are paid out,
used or applied in accordance with this Agreement.
(b) The Company hereby agrees that it shall not have
any beneficial interest in or rights to any moneys or Government
Obligations, or proceeds thereof or interest or income earned thereon, on
deposit in the Escrow Account or payments made therefrom so long as any of
the Notes or any amounts owing to the Escrow Agent hereunder remain unpaid.
SECTION 9. Liability of Escrow Agent. In performing any
duties under this Agreement, the Escrow Agent shall not be liable to any
party for damages, losses or expenses, except for gross negligence or
willful misconduct on the part of the Escrow Agent. The Escrow Agent shall
not incur any such liability for (A) any act or failure to act made or
omitted in good faith, or (B) any action taken or omitted in reliance upon
any instrument, including any written statement or affidavit provided for
in this Agreement that the Escrow Agent shall in good faith believe to be
genuine, nor will the Escrow Agent be liable or responsible for forgeries,
fraud, impersonations or determining the scope of any representative
authority. In addition, the Escrow Agent may consult with legal counsel in
connection with the Escrow Agent's duties under this Agreement and shall be
fully protected in any act taken, suffered or permitted by him/her in good
faith in accordance with the advice of counsel. The Escrow Agent is not
responsible for determining and verifying the authority of any person
acting or purporting to act on behalf of any party to this Agreement.
SECTION 10. Termination; Income From Government
Obligations. (a) Except as set forth in Section 1, this Agreement shall
terminate when the principal of the Notes and Basic Interest thereon to the
Stated Maturity Date shall have been paid in the manner set forth in
Section 11 of this Agreement.
(b) After termination of this Agreement in accordance
with the provisions of subsection (a) of this Section 10, all income from
all Government Obligations in the hands of the Escrow Agent pursuant to
this Agreement which is not required for the payment of the Defeasance
Requirements or amounts owing to the Escrow Agent hereunder shall be paid
to the Company as and when requested in writing by the Company.
SECTION 11. Payment. (a) All amounts payable hereunder
to the Holders with respect to any Notes held by the Holders or its or
their nominee (without the necessity for any presentation or surrender
thereof or any notation of such payment thereon) shall be made by bank wire
transfer of Federal or other immediately available funds, providing
sufficient information to identify the source of the transfer and the
amount of interest, premium and/or principal, to such account as specified
by the Holder to the Escrow Agent in writing, which in the case of the
Lender, shall be to the following account, unless otherwise specified in
writing:
Principal Mutual Life Insurance
Company Account No. 014752
Norwest Bank Des Moines, N.A.
7th and Walnut Streets
Des Moines, Iowa 50304
ABA No. 0730 0022 8
Bond Number 1-B-22099
(b) The Lender agrees that in the event the Lender sells,
assigns or transfers any Notes, it will, prior to any such sale, assignment
or transfer promptly notify the Escrow Agent of the name and address of the
transferee of any Note so transferred.
SECTION 12. Fees and Expenses. It is understood that the
fees and usual charges agreed upon for services of the Escrow Agent shall
be considered compensation for ordinary services as contemplated by this
Agreement. In the event that the conditions of this Agreement are not
promptly fulfilled, or if the Escrow Agent renders any service not provided
for in this Agreement, or if the parties request a substantial modification
of its terms, or if any controversy arises, or if the Escrow Agent is made
a party to, or intervenes in, any litigation pertaining to this escrow or
its subject matter, the Escrow Agent shall be reasonably compensated for
such extraordinary services and reimbursed for all reasonable costs,
attorney's fees, including allocated costs of in-house counsel, and
expenses occasioned by such default, delay, controversy or litigation and
the Escrow Agent shall have the right to retain all documents and/or other
things of value at any time held by the Escrow Agent in this escrow until
such compensation, fees, costs and expenses are paid. The Company promises
to pay these sums upon demand in accordance with the fee schedule attached
hereto as Exhibit D.
SECTION 13. Defeasance. The Company and the Holders have
agreed that the Defeasance Agreement shall become effective on the
Effectiveness Date.
SECTION 14. Benefit of Agreement; Amendments. This
Agreement is made for the benefit of the Company and the Holders. This
Agreement shall not be repealed, revoked, altered or amended without the
written consent of the Company and all of the Holders and the written
consent of the Escrow Agent.
SECTION 15. Controversies. If any controversy arises
between the parties to this Agreement, or with any other party, concerning
the subject matter of this Agreement, its terms or conditions, the Escrow
Agent will not be required to determine the controversy or to take any
action regarding it. The Escrow Agent may hold all documents and funds and
may wait for settlement of any such controversy by final appropriate legal
proceedings or other means as, in the Escrow Agent's discretion, the Escrow
Agent may be required, despite what may be set forth elsewhere in this
Agreement. In such event, the Escrow Agent will not be liable for interest
or damage. Furthermore, the Escrow Agent may at its option, file an action
of interpleader requiring the parties to answer and litigate any claims and
rights among themselves. The Escrow Agent is authorized to deposit with
the clerk of the court all documents and funds held in escrow, except all
costs, expenses, charges and reasonable attorney fees incurred by the
Escrow Agent due to the interpleader action and which the parties jointly
and severally agree to pay. Upon initiating such action, the Escrow Agent
shall be fully released and discharged of and from all obligations and
liability imposed by the terms of this Agreement.
SECTION 16. Indemnification of Escrow Agent. The Company
and its respective successors and assigns agrees to indemnify and hold the
Escrow Agent harmless against any and all losses, claims, damages,
liabilities and expenses, including reasonable costs of investigation,
counsel, fees, including allocated costs of in-house counsel and
disbursements, that may be imposed on the Escrow Agent or incurred by the
Escrow Agent in connection with the performance of his/her duties under
this Agreement, including but not limited to any litigation arising from
this Agreement or involving its subject matter. The Escrow Agent shall
have a first lien on the property and papers held under this Agreement for
such compensation and expenses.
SECTION 17. Investment Instructions. For the purpose of
investing funds held in escrow, the Escrow Agent may accept and act upon
the joint written instructions of the Company and all of the Holders. The
parties shall indemnify and hold the Escrow Agent harmless from any and all
liability for acting on a joint written investment instruction purported to
be given by the Company and all the Holders. The Escrow Agent shall not be
responsible for the authenticity of any instructions or be in any way
liable for any unauthorized instruction or for acting on such an
instruction, whether or not the persons giving the instructions were, in
fact, authorized. In no event shall the Escrow Agent be liable to the
Company for any consequential, special, or exemplary damages, including but
not limited to lost profits, from any cause whatsoever arising out of, or
in any way connected with acting upon written instructions believed by the
Escrow Agent to be genuine.
The Escrow Agent will act upon investment instructions the
day that such instructions are received, provided the requests are
communicated within a sufficient amount of time to allow the Escrow Agent
to make the specified investment. Instructions received after an
applicable investment cutoff deadline will be treated as being received by
the Escrow Agent on the next business day, and the Escrow Agent shall not
be liable for any loss arising directly, or indirectly, in whole or in
part, from the inability to invest funds on the day the instructions are
received. The Escrow Agent shall not be liable for any loss incurred by
the actions of third parties or by any loss arising by error, failure or
delay in making of an investment which is caused by circumstances beyond
the Escrow Agent's reasonable control.
SECTION 18. Backup Withholding. The Escrow Agent and the
Company, as the case may be, shall provide all necessary information,
documentation or certification to the payor of interest, principal, premium
or other "reportable payments" made with respect to the Escrowed Securities
or other assets held by the Escrow Agent pursuant to this Agreement so that
such payments will not be subject to "backup withholding" tax under section
3406 of the Internal Revenue Code of 1986, as amended. Attached hereto as
Exhibit E is a properly and accurately prepared and duly executed Internal
Revenue Service Form W-9 certifying that the Company is exempt from "backup
withholding" tax.
SECTION 19. Resignation of Escrow Agent. The Escrow
Agent may resign at any time upon giving at least thirty (30) days' written
notice to the Company; provided, however, that no such resignation shall
become effective until the appointment of a successor escrow agent which
shall be accomplished as follows: The Company shall use its best efforts
to select a successor escrow agent within thirty (30) days after receiving
such notice. If the Company fails to select a successor escrow agent
within such time, the Escrow Agent shall have the right to appoint a
successor escrow agent authorized to do business in the state of
California. In each case, the successor escrow agent shall be reasonably
acceptable to all the Holders. The successor escrow agent shall execute
and deliver an instrument accepting such appointment and it shall, without
further acts, be vested with all the estates, properties, rights, powers
and duties of the predecessor escrow agent as if originally named as escrow
agent. The Escrow Agent shall be discharged from any further duties and
liability under this Agreement.
SECTION 20. Governing Law. This Agreement is to be
construed and interpreted according to California law.
SECTION 21. Counterparts. This Agreement may be executed
in several counterparts, all or any of which shall be regarded for all
purposes as one original and shall constitute and be but one and the same
instrument.
SECTION 22. Section Headings. The headings of the
several Sections hereof and the Table of Contents appended hereto shall be
solely for convenience of reference and shall not affect the meaning,
construction, interpretation or effect of this Agreement.
IN WITNESS WHEREOF, the parties have each caused this
Agreement to be executed by their duly authorized officers on the date
first above written.
CALIFORNIA ENERGY COMPANY, INC.
By
Name:
Title:
BANK OF AMERICA NATIONAL TRUST
AND SAVINGS ASSOCIATION,
as Escrow Agent
By
Name:
Title:
ACKNOWLEDGED AND AGREED BY:
PRINCIPAL MUTUAL LIFE INSURANCE COMPANY
By
Name:
Title:
By
Name:
Title:
EXHIBIT A
Defeasance Agreement
EXHIBIT B
Government Obligations
<TABLE>
<CAPTION>
Accrued
Type Coupon Maturity Par Amount Price Yield Interest Total Cost
<S> <C> <C> <C> <C> <C> <C> <C>
TNOTE 4.250 8/31/94 1,394,000.0 100.296271* 3.588020 2,414.88* 1,400,544.90*
TNOTE 3.875 2/28/95 37,154,000.00 99.800470* 4.087660 58,684.14* 37,138,530.76*
------------- ---------- --------------
38,548,000.00 61,099.02* 38,539,095.66*
Cash: 797.65
Securities: 38,539,095.66
-------------
Total Cost: 38,539,893.31
* Approximate. Subject to change on Effectiveness Date.
EXHIBIT C
Defeasance Requirements
<TABLE
<CAPTION>
Date Principal Interest Total
<S> <C> <C> <C>
9/15/94 -- $2,143,828.80 $ 2,143,828.80
3/15/95 $35,730,480 $2,143,828.80 $37,874,308.80
Portfolio Less: Cumulative
Date Principal Interest Total Income Requirement Balance
<S> <C> <C> <C> <C> <C>
3/15/94 0.00 0.00 0.00 0.00 797.65
8/31/94 1,394,000.00 749,481.25 2,143,481.25 0.00 2,144,278.90
9/15/94 0.00 0.00 0.00 2,143,828.80 450.10
2/28/95 37,154,000.00 719,858.75 37,873,858.75 0.00 37,874,308.85
3/15/95 0.00 0.00 0.00 37,874,308.80 0.05
------------- ------------ ------------- -------------
38,548,000.00 1,469,340.00 40,014,340.00 40,018,137.60
</TABLE>
Exhibit D
Fee Schedule
Exhibit E
Form W-9
AMENDMENT NO. 3 TO STOCK PURCHASE AGREEMENT
AMENDMENT NO. 3 dated as of April 2, 1993, to the Stock Purchase
Agreement dated as of February 18, 1991, as amended (the "Stock Purchase
Agreement"), between KIEWIT ENERGY COMPANY, a Delaware corporation
("Kiewit"), and CALIFORNIA ENERGY COMPANY, INC., a Delaware corporation
(the "Company").
Kiewit and the Company agree to amend the Stock Purchase Agreement as
follows, such amendment to become effective as of April 19, 1993:
All references to the "Officer" in Exhibit F (Future Opportunities)
of the Stock Purchase Agreement shall mean Richard Jaros, Chairman of the
Board of California Energy Company, Inc.
KIEWIT ENERGY COMPANY
BY: /s/ Robert E. Julian
Robert E. Julian
Vice President
CALIFORNIA ENERGY COMPANY, INC.
BY: /s/ Steven A. McArthur
Steven A. McArthur
Vice President
AMENDMENT NO. 4 TO SHAREHOLDER'S AGREEMENT
AMENDMENT NO. 4 dated as of July 20, 1993, to the
Shareholder's Agreement dated as of February 18, 1991, as amended
(the "Shareholder's Agreement"), between KIEWIT ENERGY COMPANY,
INC., a Delaware corporation ("Kiewit"), and CALIFORNIA ENERGY
COMPANY, INC., a Delaware corporation (the "Company").
Kiewit and the Company agree to amend the Shareholder's
Agreement as follows, such amendment to become effective as of
July 20, 1993:
Section 5 of the Shareholder's Agreement is amended by
adding the following new paragraph after the existing text:
"If the Company shall determine to issue Company Securities
so as to trigger Kiewit's pre-emptive right hereunder to purchase
the Offered Securities, and if under applicable New York Stock
Exchange rules the issuance to Kiewit of any or all of the
Offered Securities would require shareholder approval (unless
issued pursuant to a public offering), then the Company agrees
that it will only issue such Company Securities in a public
offering or pursuant to shareholder approval or if Kiewit waives
it pre-emptive right with respect to such issuance of Company
Securities."
KIEWIT ENERGY COMPANY, INC.
By: /s/ Richard R. Jaros
Richard R. Jaros
Vice President
CALIFORNIA ENERGY COMPANY, INC.
By: /s/ Steven A. McArthur
Steven A. McArthur
Vice President
EMPLOYMENT AGREEMENT
This Employment Agreement is entered into as of April 2, 1993, by and
between California Energy Company, a Delaware corporation (the "Company"), and
David L. Sokol (the "Executive").
RECITALS
The Company desires to employ the Executive as its President and Chief
Executive Officer on the terms set forth in this Agreement, and the Executive
desires to accept such employment.
Accordingly, the Company and the Executive agree as follows:
AGREEMENT
Section 1. Defined Terms. Terms used but not defined in this Agreement
will have the meanings ascribed to them in Exhibit A to this Agreement.
Section 2. Employment.
(a) The Company will employ the Executive as, and the Executive
will act as, the President and Chief Executive Officer of the Company upon the
terms set forth in this Agreement, for the Term of Employment.
(b) The Executive's primary place of employment will be Omaha,
Nebraska or such other place as is determined by the Board to be in the best
interest of the Company. However, after reestablishing his residence in
Omaha, Nebraska, the Executive will not be required to relocate from such
residence.
Section 3. Duties.
(a) The Executive (i) will manage the business of the Company
and supervise and direct the other officers of the Company (except the
Chairman of the Board) and its employees, agents and representatives, and (ii)
will perform and discharge such other duties, and will have such other
authority, as are customary to his office. In performing such duties, the
Executive will report directly to the Chairman of the Board and will consult
with the Chairman of the Board regarding significant decisions and strategic
options for the Company.
(b) The Board will not reduce the title, office, duties or
authority of the Executive in any material respect except pursuant to Section
7. During the Term of Employment, the Company will use its best efforts to
cause the Executive to be nominated and elected to the Company's Board of
Directors.
(c) The Executive will act, without any compensation in addition
to the compensation payable pursuant to this Agreement, as an officer of any
subsidiary of the Company, or as a member of the Board of the board of
directors of any subsidiary of the Company, if so appointed or elected.
(d) During the Term of Employment, the Executive (i) will devote
his entire time, attention and energies during normal business hours to the
business of the Company, and (ii) will not, without the Consent of the Board,
perform any services for any other Person or engage in any other business or
professional activity, whether or not performed or engaged in for profit.
<PAGE>
(e) Notwithstanding subsection (d), the Executive, without the
Consent of the Board, may (i) perform the consulting duties contemplated the
letter agreement dated October 5, 1990, by and among the Executive, Ogden
Corporation and Ogden Projects, Inc. (ii) purchase securities issued by,
or otherwise passively invest his personal or family assets in, any other
company or business, and (iii) engage in governmental, political, educational
or charitable activities, but only to the extent that those activities (A) are
not inconsistent with any direction of the Board or any duties under this
Agreement, and (B) do not interfere with the devotion by the Executive of his
entire time, attention and energies during normal business hours to the
business of the Company.
Section 4. Compensation.
(a) During the Term of Employment, the Company will pay the
Executive a base salary at an annual rate of $350,000, in substantially equal
periodic payments in accordance with the Company's practices for executive
employees, as determined from time to time by the Board.
(b) The Board will review the salary payable to the Executive
at least annually beginning in the fourth fiscal quarter of 1993. The Board,
in its discretion, may increase the salary of the Executive from time to time,
but may not reduce the salary of the Executive below the amount set forth in
subsection (a).
(c) During the Term of Employment, the Company will pay the
Executive an annual bonus, not later than ten calendar days after the
completion of the financial statements or audit of the Company for the
preceding fiscal year of the Company in an amount determined by the Board, by
reference to the accomplishment by the Executive of goals established by the
Board for the related fiscal year. The annual bonus paid to the Executive,
however, will not be less than the Minimum Bonus.
(d) If the Executive suffers a Disability which continues for
more than 60 consecutive calendar days, the Company may elect to pay the
Executive, for so long as the Disability continues, fifty (50) percent of the
salary otherwise payable to the Executive under Section 4(a), and fifty (50)
percent of the Minimum Bonus otherwise payable to the Executive pursuant to
Section 4(c). Any such election will not affect the rights of the Company
under Section 7(a)(v).
(e) (i) The Company will issue to the Executive, within five
business days after the date of this Agreement, options under the Company's
1986 Stock Option Plan to acquire 250,000 shares of the common stock of the
Company at an exercise price equal to the closing price for the common stock
on the American Stock Exchange on April 2, 1993, of which options to purchase
100,000 shares shall vest immediately and the remaining 150,000 options shall
vest at an equal monthly rate over the next four (4) years. The terms and
provisions of the option will be similar in all other material respects to the
other options granted to the senior executives of the Company.
(ii) The Company and the Executive have agreed in
principle that a grant of 1,000,000 options in the aggregate over five (5)
years is the expected grant amount to be made over such period of employment,
which grants would be at the discretion of the Board, assuming Executive's
satisfactory performance of his duties hereunder. In light of this
expectation, the Board will review the number of options granted to the
Executive at least annually beginning in the fourth fiscal quarter of 1993.
However the Board may, in its discretion, increase or decrease the number of
options expected to be granted hereunder (except for the 250,000 options
granted under (i) above).
(f) The Company will reimburse the Executive, (i) subject to
compliance by the Executive with the Company's customary reimbursement
practices, for all reasonable and necessary out-of-pocket expenses incurred
by the Executive on behalf of the Company in the course of its business and
(ii) for all costs and expenses incurred in relocating his residence from New
York to Omaha which are reimbursable under the Company's relocation plan.
(g) The Company may reduce any payments made to the Executive
under this Agreement by any required federal, state or local government
withholdings or deductions for taxes or similar charges, or otherwise pursuant
to law, regulation or order.
(h) The compensation payable to the Executive pursuant to this
Agreement will be in consideration for all services rendered by the Executive
under this Agreement, and the Executive will receive no other compensation
from the Company.
(i) Any base salary or Minimum Bonus payable to the Executive
for any period of employment of less than a year during the Term of Employment
will be reduced to reflect the actual number of days of employment during the
period except as provided in Section 8(b).
Section 5. Other Benefits.
(a) During the Term of Employment, the Executive and his family
may participate in and receive benefits under any employee benefit plan which
the Company makes generally available to its employees and their families,
including any pension, life insurance, medical benefits, dental benefits or
disability plan, but only to the extent that the Executive or his family
otherwise satisfies the standards established for participation in the plan.
(b) The Executive may take up to four weeks of vacation during
each full calendar year during the Term of Employment, without loss of
compensation or other benefits under this Agreement.
Section 6. Confidentiality and Post-Employment Restrictions.
(a) The Executive acknowledges that the Company has confidential
information and trade secrets, whether written or unwritten, with respect to
carrying on its business, including sensitive technology and engineering
information and data, names of past, present and prospective customers and
vendors of the Company, methods of pricing contracts and income and expenses
associated therewith, negotiated prices and offers outstanding, credit terms
and status of accounts and the terms or circumstances of any business
arrangements between the Company and any third parties ("Confidential
Information and Trade Secrets"). As used in this Agreement, the term
Confidential Information and Trade Secrets does not include (i) information
which becomes generally available to the public other than as a result of a
disclosure by the Executive, (ii) information which becomes available to the
Executive on a nonconfidential basis from a source other than the Company, or
(iii) information known to the Executive prior to any disclosure to him by the
Company. The Executive further acknowledges that the Executive possesses a
high degree of knowledge of the geothermal energy industry and, in particular,
has committed to a long-standing relationship with the Company as employee,
director and officer, which has allowed, and will continue to allow, him
access to the Company's Confidential Information and Trade Secrets.
Accordingly, any employment by the Executive with another employer in the
geothermal energy industry or participation by him as a substantial investor
in any such industry may necessarily involve disclosure of the Company's
Confidential Information and Trade Secrets. Consequently, the Executive
agrees that, if he voluntarily resigns his employment with the Company for any
reason other than a breach of this Agreement by the Company, he shall not at
any time during the two-year period after such resignation, directly or
indirectly accept employment by or invest in (except as a passive investor in
a public corporation or in a publicly issued partnership interest which, in
either event, would not exceed an ownership interest of 3% of the outstanding
equity or partnership interest) in any person, firm, corporation, partnership,
joint venture or business which is primarily engaged in the production or
marketing of electrical energy from geothermal resources.
(b) Without the Consent of the Board, the Executive will not,
for two years after the Term of Employment, (i) disclose any Confidential
Information and Trade Secrets of the Company or any Affiliate of the Company
to any Person (other than the Company, directors, officers or employees of the
Company or representatives thereof), or (ii) otherwise make use of any
Confidential Information and Trade Secrets other than in connection with
authorized dealings with or by the Company.
(c) For a period of two years after the Term of Employment, the
Executive shall neither directly nor indirectly solicit, on behalf of another
employer, the employment of any person who is then currently employed by the
Company, or otherwise induce, on behalf of another employer, such person to
leave the employment of the Company without the Company's prior written
approval.
(d) The Executive will hold, on behalf of the Company and as the
property of the Company, all memoranda, manuals, books, papers, letters,
documents, computer software and other similar property obtained during the
course of his employment by the Company and relating to the Company's
business, and will return such property to the Company at any time upon demand
by the Board and, in any event, within five calendar days after the end of the
Term of Employment.
Section 7. Termination of Employment.
(a) The employment of the Executive under this Agreement will
terminate on the earliest of: (i) written notice by the Executive of his
resignation; (ii) the 30th calendar day after the Company gives to the
Executive written notice of termination without Cause; (iii) the fifth
calendar day after the Company gives to the Executive written notice of the
existence of Cause; (iv) the 30th calendar day after the Executive gives to
the Company written notice of (A) the failure by the Company to pay to the
Executive, for a material period of time and in a material amount,
compensation due and payable by the Company under Section 4(a) or 4(c), or (B)
any breach by the Company or the Board of Section 3(b) or Section 4(b); (v)
the Permanent Disability of the Executive; or (vi) the death of the Executive.
(b) If the employment of the Executive is terminated under this
Agreement, the obligations of the Executive under Section 6 will remain in
full force and effect, and the termination will not abrogate any rights or
remedies of the Company or the Executive with respect to any breach of the
Agreement, except as expressly provided in Sections 8 and 9.
Section 8. Payment Upon Termination.
(a) If the employment of the Executive is terminated pursuant
to subsections (i), (iii), (v), or (vi) of Section 7(a), the Company will pay
to the Executive, within 30 calendar days, (i) any salary pursuant to Section
4(a) which is accrued but unpaid through the Termination Date, and (ii) a
bonus payment, in an amount determined by the Board by reference to the
performance of the Executive for the portion of the fiscal year of the Company
before the Termination Date, which is not less than a pro rata share
(determined by reference to the portion of the fiscal year before the
Termination Date) of the Minimum Bonus.
(b) If the employment of the Executive is terminated pursuant
to subsection (ii) or subsection (iv) of Section 7(a), the Company will pay
the Executive, on or before the related Termination Date, an amount equal to
twice the sum of the annual salary and Minimum Bonus then in effect pursuant
to Section 4. In addition, any portion of the options granted pursuant to
Section 4 which would become vested within the next 24 months (beginning with
the month following the month in which the Termination Date occurs) will vest
immediately and may be exercised within the remaining term of the options as
provided in the option agreement.
Section 9. Remedies.
(a) The Company will be entitled, if it elects, to enjoin any
breach or threatened breach of, or enforce the specific performance of, the
obligations of the Executive under Sections 3 or 6, without showing any actual
damage or that monetary damages would be inadequate. Any such equitable
remedy will not be the sole and exclusive remedy for any such breach, and the
Company may pursue other remedies for such a breach.
(b) Any court proceeding to enforce this Agreement may be
commenced in the federal courts, or in the absence of federal jurisdiction the
state courts, located in Omaha, Nebraska. The parties submit to the
jurisdiction of such courts and waive any objection which they may have to
pursuit of any such proceeding in any such court.
(c) Except to the extent that the Company elects to seek
injunctive relief in accordance with subsection (a), any controversy or claim
arising out of or relating to this Agreement or the validity, interpretation,
enforceability or breach of this Agreement will be submitted to arbitration
in Omaha, Nebraska, in accordance with the then existing rules of the American
Arbitration Association, and judgement upon the award rendered in any such
arbitration may be entered in any court having jurisdiction.
(d) The Company will pay, promptly upon request, any legal fees
or expenses incurred by the Executive in connection with any legal proceedings
instituted by the Company to enforce the provisions of this Agreement against
the Executive, but such advances will be reimbursable to the Company, but only
to the extent the Company ultimately prevails in the proceeding (after any
applicable appeals have been exhausted).
Section 10. Assignment. Neither the Company nor the Executive may
sell, transfer or otherwise assign their rights, or delegate their
obligations, under this Agreement.
Section 11. Unfunded Benefits. All compensation and other benefits
payable to the Executive under this Agreement will be unfunded, and neither
the Company nor any affiliate of the Company will segregate any assets to
satisfy any obligation of the Company under this Agreement. The obligations
of the Company to the Executive are not the subject of any guarantee or other
assurance of any Person other than the Company.
Section 12. Severability. Should any provision, paragraph, clause or
portion thereof of this Agreement be declared or be determined by any court
or arbitrator of competent jurisdiction to be illegal, unenforceable or
invalid, the validity or enforceability of the remaining parts, terms or
provisions shall not be affected thereby and said illegal or invalid part,
term or provision shall be deemed not to be a part of this Agreement.
Alternatively, the court or arbitrator having jurisdiction shall have the
power to modify such illegal, unenforceable or invalid provision so that it
will be valid and enforceable, and, in any case, the remaining provisions of
this Agreement shall remain in full force and effect.
Section 13. Miscellaneous.
(a) This Agreement may be amended or modified only by a writing
executed by the Executive and the Company.
(b) This Agreement will be governed by and construed in
accordance with the internal laws of the State of Nebraska.
(c) This Agreement constitutes the entire agreement of the
Company and the Executive with respect to the matters set forth in this
Agreement and supersedes any and all other agreements between the Company and
the Executive relating to those matters.
(d) Any notice required to be given pursuant to this Agreement
will be deemed given (i) when delivered in person, or (ii) on the third
calendar day after it is sent by facsimile, express delivery service, or
registered or certified mail, if to the Company at 10831 Old Mill Road, Omaha,
Nebraska, 68154, and if to the Executive at 516 Cross River Road, Katonah, NY
10536, or to such other address as may be designated by the Company or the
Executive in writing to the other party.
(e) A waiver by a party of a breach of this Agreement will not
constitute a waiver of any other breach, prior or subsequent, of this
Agreement.
IN WITNESS WHEREOF, the Company and the Executive have entered into this
Agreement as of April 2, 1993.
CALIFORNIA ENERGY COMPANY, INC.
BY: /s/ Steven A. McArthur
Steven A. McArthur
Vice President
EXECUTIVE:
BY: /s/ David L. Sokol
David L. Sokol<PAGE>
EXHIBIT A
Defined Terms
"Affiliate" means, with respect to a Person, (a) any Person directly or
indirectly owning, controlling, or holding power to vote 10% or more of the
outstanding voting securities of the Person; (b) any Person 10% or more of
whose outstanding voting securities are directly or indirectly owned,
controlled or held with power to vote by the Person; (c) any Person directly
or indirectly controlling, controlled by or under common control with, the
Person and (d) any officer or director of the Person, or of any Person
directly or indirectly controlling the Person, controlled by the Person or
under common control with the Person. As used in this definition, "control"
means the possession, directly or indirectly, of the power to direct or cause
the direction of the management and policies of a Person.
"Agreement" means this Employment Agreement dated as of April 2, 1993,
by and between the Company and the Executive, as it may be amended from time
to time in accordance with its terms.
"Board" means the Board of Directors of the Company or, if the context
is appropriate, any duly authorized and appointed committee or member of the
Board of Directors having authority to act on behalf of the Board of Directors
with respect to the matter in question.
"Cause" means any or all of the following:
(a) the willful and continued failure by the Executive to perform
substantially the services contemplated by the Agreement (other
than any such failure resulting from the Executive's incapacity
due to disability) after a written demand for substantial
performance is delivered to the Executive by a member or
representative of the Board which specifically identifies the
manner in which it is alleged that the Executive has not
substantially performed such services;
(b) the willful engaging by the Executive in gross misconduct which
is materially and demonstrably injurious to the Company, provided
that, no act, or failure to act, on the Executive's part shall be
considered "willful" unless done, or omitted to be done, in bad
faith and without reasonable belief that such action or omission
was in, or not opposed to, the best interests of the Company; or
(c) the gross negligence of the Executive in performing the services
contemplated by the Agreement which is materially and
demonstrably injurious to the Company.
Cause will exist only if the Board has delivered to the Executive a copy
of a resolution duly adopted by the affirmative vote of a majority of the
entire membership of the Board at a meeting of the Board called and held for
that purpose (after reasonable notice to the Executive and an opportunity for
the Executive, together with his counsel, to be heard before the Board),
finding that, in the good faith judgement of the Board, the Executive was
guilty of the conduct constituting such Cause and specifying the particulars
thereof in detail.
"Company" means California Energy Company, Inc., a Delaware corporation,
and any successor or assign permitted under the Agreement.
"Consent of the Board" means, with respect to an action, the consent of
the Board to the action given prior to the action in a resolution duly adopted
by the Board, appropriate committee of the Board, or by a member of the Board
duly authorized to consent to such action.
"Disability" means, with respect to the Executive, that the Executive
has become physically or mentally incapacitated or disabled so that, in the
reasonable judgement of majority of the members of the Board, he is unable to
perform his duties under this Agreement and such other services as he
performed on behalf of the Company before incurring such incapacity or
disability.
"Minimum Bonus" means, with respect to a fiscal year, $75,000.
"Permanent Disability" means a Disability which has continued for at
least six consecutive calendar months.
"Person" means any natural person, general partnership, limited
partnership, corporation, joint venture, trust, business trust, or other
entity.
"Term of Employment" means the period of time beginning on April 19,
1993 and ending on the third anniversary of such date, unless earlier
terminated pursuant to Section 7(a) or automatically extended pursuant to the
following sentence. The Term of Employment will be automatically extended for
one year on each anniversary of the date of this Agreement beginning on the
third anniversary unless the Executive has given the Company a notice
declining automatic extension at least 120 calendar days before the
anniversary.
"Termination Date" means the date of termination of employment of the
Executive pursuant to Section 7 of this Agreement.
EXHIBIT 10.41
TERMINATION AGREEMENT
This Termination Agreement is entered into between California Energy
Company, Inc. (the "Company") and Richard R. Jaros (the "Executive") as of
December 9, 1993 in order to terminate the Employment Agreement between the
Company and the Executive dated as of January 8, 1992, as amended on April
5, 1993 (as so amended, the "Employment Agreement").
The Company and the Executive agree to terminate the Employment
Agreement pursuant to the following terms and conditions:
1. Effective upon the payment by the Company to the Executive of a lump sum
of $250,000, less any applicable withholding taxes (such sum payable in
part as a bonus in recognition of the Executive's meritorious service
under the Employment Agreement and in part as a severance payment in
consideration for the Executive's agreement to terminate the Employment
Agreement prior to the end of its term), the Employment Agreement
(except the provisions of Section 6 thereof) shall be terminated as of
December 31, 1993. The Company and the Executive agree that the
confidentiality provisions and post-employment restrictions of Section 6
of the Employment Agreement shall continue to apply so long as Executive
serves as Chairman of the Board or otherwise as an officer of the
Company and for a two-year period thereafter. The parties acknowledge
that this termination of the Employment Agreement shall not in any way
affect (i) the Executive's 401(k) account balance as of December 31,
1993, which may remain in the plan (although no further contributions to
the 401(k) plan will be made by the Executive) or (ii) the continued
vesting or other terms of the 410,000 stock options previously granted
to the Executive under separate Agreements of Grant with the Company
dated December 5, 1991, January 8, 1992 and December 2, 1992.
2. The Company and the Executive acknowledge that, effective January 1,
1994 the Executive shall serve as Chairman of the Board (an officer
position under the Company's By-laws) at the pleasure of the Company's
Board of Directors ("Board") and shall be entitled to receive such fee,
if any, as the Board from time to time deems appropriate but not in
excess of the $25,000 per annum fee established by Board resolution at
the Board's December 7, 1993 meeting and that any such employment as
Chairman of the Board or otherwise as an officer of the Company shall be
at-will and may be terminated without notice at any time by the Board or
the Executive without liability of any kind. It is understood that the
at-will nature of Executive's employment as an officer does not affect
any rights of Kiewit Energy Company ("Kiewit") to nominate Executive as
a director of the Company under the existing Shareholders Agreement, as
amended, between the Company and Kiewit. The Company and the Executive
also acknowledge that until March 31, 1994 (in order to provide the
Executive with a reasonable interim coverage period in which to transfer
his medical plan participation) he shall be entitled to participate in
the Company's medical benefits plans under the terms and conditions
available to other employees.
3. Upon payment of the $250,000 lump sum (less any applicable withholding
taxes) and this Termination Agreement becoming effective in accordance
with the terms of paragraph 1, the following release shall become
effective:
The Executive, on behalf of himself, his successors, assigns, agents and
persons claiming through him or on his behalf, shall release and forever
discharge the Company, its partners, employees, agents, representatives,
attorneys, assigns and successors in interest, from any and all claims,
actions, causes of action, liabilities, demands, losses and damages of
any kind whatsoever, whether known or unknown, suspected or unsuspected,
which now exist or which may hereafter accrue, arising out of or
relating to any facts occurring prior to the effective date of this
Termination Agreement. The released claims shall include, but not be
limited to, all claims, issues, obligations or liabilities relating to
the termination of the Employment Agreement.
4. Miscellaneous: This Termination Agreement may only be amended or
modified by a written agreement executed by both parties.
This Termination Agreement shall be governed by and construed in
accordance with the internal laws of the State of Nebraska.
IN WITNESS WHEREOF, the Company and the Executive have entered into this
agreement as of December 9, 1993, which shall become effective as set forth
in Section 2 above.
CALIFORNIA ENERGY COMPANY, INC.
By: /s/ Steven A. McArthur
Steven A. McArthur
Vice President
EXECUTIVE
By: /s/ Richard R. Jaros
Richard R. Jaros
EXHIBIT 10.42
STANDARD OFFER NO. 2
STANDARD OFFER FOR POWER PURCHASE
WITH
A FIRM CAPACITY QUALIFYING FACILITY
(BONNEVILLE PACIFIC CORPORATION)
File No. QFE 200.416
Revised March 7, 1990
SO2-6
TABLE OF CONTENTS
SECTION TITLE PAGE
1. Parties 1.
2. Project Summary 1.
3. Definitions 5.
4. Project Fee 15.
5. Project Development Milestone 17.
6. Effective Date and Term 31.
7. Purchase of Energy 32.
8. Method of Purchase and Sale 32.
9. Purchase of Capacity 34.
10. Seller's General Obligations 45.
11. SDG&E's General Obligations 50.
12. Interconnection Facilities 51.
13. Cancellation Charges 53.
14. Billing and Payment 54.
15. Metering of Energy Deliveries 55.
16. Continuity of Service 57.
17. Default Remedies 67.
18. Abandonment 70.
19. Nondedication of Facilities 71.
20. Liability 71.
21. Insurance 72.
22. Uncontrollable Force 74.
23. Non-Waiver 74.
-i-
SECTION TITLE PAGE
24. Successors & Assigns 75.
25. Effect of Section Headings 75.
26. Governing Law 75.
27. Several Obligations 76.
28 Conditions 76.
Signatures 78.
EXHIBITS
A - Site Location Metes and Bounds Description (if
necessary)
B - Time Periods
C - Schedules for Payments of Firm Capacity
D - QF Quarterly Status Report
E - Reduction and Termination Payment Example
F - SDG&E's Electric Department Rule 21
-ii-
1. PARTIES
The Parties to this Agreement are Bonneville Pacific Corporation
(Seller), a Delaware Corporation and San Diego Gas & Electric Company (SDG&E),
a California corporation (individually "Party", collectively "Parties"), who
agree as follows:
2. PROJECT SUMMARY
Seller represents that the statements made below are true and selects
the options to this Agreement specified below, which options are described in
more detail in the Sections referenced below:
2.1 Seller's Generating Facility:
2.1.1 Nameplate Rating (Net of Station Load) 52,890 kw
2.1.2 Interconnection Voltage Level at the Generating
Facility boundary/69 kV For out-of-service area
Sellers only;
(a) The Point of Delivery North Gila Substation and
(b) The Designated Point of Interconnection Miguel
Substation
2.1.3 Location (out of service area):
Yuma, AZ (See Exhibit A) (if address not available,
append metes and bounds description)
(Exhibit A)
2.1.4 Type of Facility:
X Cogeneration Facility
X Small Power Production Facility
2.1.5 Scheduled Firm Capacity Operation Date (Section 5.9)
January 1, 1993.
2.1.6 Term as measured from the Scheduled Firm Capacity
Operation Date (Section 6.1) 30 years.
2.2 Purchase Price of Capacity.
2.2.1 Amount of Firm Capacity (Section 9.3) 50,000 kW
2.2.2 Seller shall provide Firm Capacity according to (check
one) (Section 9.3):
X Option 1 - Dispatchable
Option 2 - Actually Delivered
2.2.3 Seller chooses to have Firm Capacity Payments based on
(check one) (Section 9.4):
X Option 1 - Schedule in effect at time of
execution (attached as Exhibit C).
Option 2 - Schedule in effect on the Scheduled Firm
Capacity Operation Date.
2.2.3.1 If Seller chooses Option 1:
Price per kw of Firm Capacity will be
$140 /kw-yr
2.3 Method of Purchase and Sale (check one)
(Section 8.1):
N/A Simultaneous Purchase and Sale
N/A Sale of Surplus Energy
X Off System Sales
2.4 Project Development Material Milestones:
2.4.1 Provide inform- Not later than
ation for and pay three (3) months
costs of Prelimi- after the date of
nary Interconnec- execution of this
tion/Operating Agreement or such
Study pursuant to other date as
Section 5.4. agreed to by the
parties.
See Section 5.4.
2.4.2 (For out-of-ser- Not later than six
vice area Generat- (6) months from
ing Facilities the date of execut
only) Provide ion of this agree-
acceptable proof ment.
that Seller has
obtained rights
for transmission
of power to the
designated SDG&E
point of delivery
(Section 5.5).
2.4.3 Provide informat- Not later than the
ion and pay cost date specified in
for SDG&E to con- 2.4.4.
duct a Line Loss See Section 5.6.
and Transmission
Impact Study
(Section 5.6).
2.4.4 Provide informat-
ion for and pay
costs of Detailed Not later than 6
Interconnection/ months following
Operating Study the date of execu-
pursuant to tion of this
Section 5.7. agreement.
2.4.5 Commence construc-
tion of the
Generating Faci- Not later than 18
lity pursuant to months prior to
Section 5.8: the date specified
in 2.4.6
2.4.6 Establish Reliable Not later than
Operation of the December 31, 1994.
Generating Faci-
lity pursuant to
Section 5.9.
2.5 Seller selects the following metering locations
Section 15.1):
(a) For Sellers located within SDG&E Operating
system:
N/A Metering on SDG&E's side of
Interconnection Facilities.
N/A Metering on Seller's side
of Interconnection Facilities.
Transformer Loss Compensation Factor N/A%
(b) For out-of-service area Generating Facilities
metering location to be as specified in the Three
Party Operating Agreement.
2.6 NOTICES
Any formal communication or notice in connection with the
Agreement shall be in writing and shall be deemed properly
given if delivered in person or sent by first class mail,
postage prepaid, to the person specified below:
San Diego Gas & Electric Company
c/o Secretary
P.O. Box 1831
San Diego, CA 92112
Bonneville Pacific Corporation
c/o Secretary
257 East 200 South, Suite 800
Salt Lake City, Utah 84111
3. DEFINITIONS
3.1 Agreement: This Standard Offer for Power Purchase and
Interconnection with a Firm Capacity Qualifying Facility between
SDG&E and Seller, and exhibits, as amended from time to time.
3.2. Alternative Energy Cost
The lowest estimated expense per Mw-hr which SDG&E would otherwise
have incurred in generating or purchasing 100 Mw of energy from
alternative sources. The value is currently determined by SDG&E's
Energy Control Center and recorded hourly on the California Power
Pool Economy Energy Transactions Log as the system decremental
value.
3.3 As-Available Capacity: That capacity level, up to the Nameplate
Rating of the Generating Facility, Seller makes available to SDG&E
from Initial Operation to the time Generating Facility achieves
Reliable Operation per the terms of this Agreement.
3.4 As-Available Capacity Payment Schedule: SDG&E's schedule of
time-differentiated payments and conditions for the purchase of
As-Available Capacity from Qualifying Facilities as updated from
time-to-time.
3.5 Bill: A written statement setting forth charges and requiring
payment for electrical service, gas service, or both, as more
fully discussed in SDG&E's Rules of Service.
3.6 Block Curtailment: A curtailment period scheduled by SDG&E
consisting of one 400 consecutive hour period or two 200
consecutive hour periods.
3.7 Capacity Factor: The net kilowatt-hours produced by the
Generating Facility after Station Load and delivered to the
Designated Point of Interconnection, for a period of time, divided
by the product of the Firm Capacity and the number of hours in the
period of time.
3.8 Capacity Payment Schedule for Firm Capacity Qualifying Facilities:
SDG&E's schedule of prices and conditions for purchase of capacity
from Firm Capacity Qualifying Facilities. The capacity prices
contained therein are derived from SDG&E's full avoided cost as
approved by the CPUC. SDG&E's current Firm Capacity Payment
Schedule is attached as part of Exhibit C. The schedule effective
for the term of this Agreement will be as specified in Sections
2.2.3 and 9.4.
3.9 Cogeneration Facility: A facility which produces electric energy
and steam or forms of useful thermal energy (such as heat), which
are used for industrial, commercial, heating, or cooling purposes,
as defined in Title 18 Code of Federal Regulations (CFR), Part
292, as of the effective date of this Agreement.
3.10 Contract Year: The twelve month period commencing with the Firm
Capacity Availability Date and each twelve month period
commencing with the anniversary of the Firm Capacity Availability
Date.
3.11 CPUC: The California Public Utilities Commission or any successor
agency having regulatory con- trol over SDG&E or its successors.
3.12 Current Capacity Payment: The $/kW-Year Capacity Payment
Schedule, published by SDG&E, at the time of termination or
reduction of Firm Capacity, assuming a term equal to the balance
of the term of the Agreement.
3.13 Detailed Interconnection/Operating Study: SDG&E's determination
of the Interconnection Facilities required to interconnect the
Generating Facility with the SDG&E system for both on and
off-system purchases for the delivery, metering and scheduling of
power, and the proper and safe operation of the Generating
Facility in parallel with the SDG&E electric system, including an
estimate of costs and construction lead time.
3.14 Designated Point of Interconnection: (applicable to
out-of-service area Sellers only) The designated point on the
SDG&E system at which power purchased under this Agreement shall
be deemed received into the SDG&E service area.
3.15 Energy: Electric energy expressed in kilowatt-hours generated by
the Generating Facility less Station Load, delivered to the
Designated Point of Interconnection and sold to SDG&E.
3.16 Energy Payment Schedule: SDG&E's schedule of time-differentiated
payments and conditions for purchase of Energy from Firm Capacity
Qualifying Facilities as updated from time-to-time. The Energy
prices contained therein will be derived from SDG&E's full avoided
operating costs, as approved by the CPUC, throughout the life of
the Agreement.
3.17 FERC: The Federal Energy Regulatory Commission or any successor
agency having a similar function.
3.18 Firm Capacity: The amount of kilowatts specified in Section
2.2.1.
3.19 Firm Capacity Availability Date: The day following the day Seller
passes a capacity demonstration test in which Seller demonstrates
the ability of the Generating Facility to deliver Firm Capacity
continuously into SDG&E's system. The capacity demonstration test
will require the Seller to operate the Generating Facility at an
average capacity factor, based on Firm Capacity, of 80% or greater
during the on-peak and semi-peak hours in a thirty (30)
consecutive day period or such shorter period as the Parties agree
is satisfactory. Calculation of the average capacity factor shall
exclude any energy associated with generation levels greater than
the Firm Capacity.
3.20 Flexible Curtailment: A curtailment period of varying length as
more fully described in Section 16.
3.21 Forced Outage: Any Generating Facility outage resulting from a
design defect, inadequate construction, operator error or a
breakdown of the mechanical or electrical equipment that fully or
partially curtails the electrical output of the Generating
Facility.
3.22 Generating Facility: All of Seller's generating units, together
with all protective and other associated equipment and
improvements owned, maintained, and operated by Seller, which are
necessary to produce electrical power, excluding associated land,
land rights, and interests in land.
3.23 Initial Operation: The day upon which the Generating Facility
commences energy deliveries to the SDG&E system.
3.24 Interconnection Facilities: Facilities and devices which are
either (1) required for the proper and safe operation of the
Generating Facility in parallel with SDG&E's electric system, or
(2) required for the delivery, metering and scheduling of power
from an out-of-service area Generating Facility; and which are
either owned by Seller or are SDG&E Facilities and which are as
described in Section 12.
3.25 Interconnection Facilities Agreement: That Agreement which must
be executed prior to Initial Operation of the Generating Facility,
which sets forth the interconnection terms and conditions for
interconnec-tion of in-service area Generating Facilities in
parallel with the SDG&E system.
3.26 Line Extension Facilities: All facilities, excluding the
Interconnection Facilities, as generally described in Section 12,
which are determined by SDG&E to be necessary to connect SDG&E's
existing system to the Point of Delivery in order to accept the
output of the Generating Facility.
3.27 Line Loss/Transmission Impact Study: For out-of-service area
Generating Facilities, that study required in addition to the
operating Study, which will identify (a) Line Losses associated
with delivery of power from the Point of Delivery to the
Designated Point ofInterconnection and (b) the extent to which
capacity on SDG&E's intertie transmission facilities will be
affected by the acceptance of power from the Generating Facility.
3.28 Meters: Any meter installed as part of the Interconnection
Facilities to measure the amount of Energy and Firm Capacity
delivered to SDG&E.
3.29 Minimum Load Condition: A situation when SDG&E's electric system
load minus the margin required for regulation of its generation
resources is equal to or less than the sum of (1) the minimum
electrical output of generating units committed for system
security; (2) the electrical output associated with firm purchases
which SDG&E is obligated to accept due to contractual terms or
penalties; and (3) the output of Qualifying Facilities providing
electricity to SDG&E.
3.30 Nameplate Rating: The gross generating capacity of the Generating
Facility less Station Use. For purposes of this Agreement,
Nameplate Rating is that rating specified in Section 2.1.1 of the
Agreement.
3.31 O&M Charge: An amount paid monthly by Seller to SDG&E to cover
the operation and maintenance of the Line Extension and SDG&E
Facilities.
3.32 Point of Delivery: The point where: (1) for Generating Facilities
located within the SDG&E system, Seller's electrical conductors
contact SDG&E's system as it shall exist whenever the deliveries
are being made or at such other point as the Parties agree in
writ-ing or (2) for out-of-service area Generating Facilities, the
point at which power delivered to SDG&E is accepted.
3.33 Preliminary Interconnection/Operating Study: SDG&E's preliminary
estimate of the costs and equipment necessary for the
interconnection and/or deliv-ery of power from the Generating
Facility to the SDG&E system. This Study may also establish the
date by which Seller must request and pay for a Detailed
Interconnection/Operating Study under Section 5.7.1.
3.34 Project Fee: The fee more fully described in Section 4, which
Seller posts and SDG&E shall hold as security for Sellers
maintaining adequate progress in the development of the Generating
Facility.
3.35 Qualifying Facility: A Cogeneration Facility or a Small Power
Production Facility as defined in section 3.9 and 3.41,
respectively.
3.36 Reliable Operation: That level of operation established as of the
Firm Capacity Availability Date. Reliable operation must occur no
later than one (1) year from the Scheduled Firm Capacity Operation
Date.
3.37 Scheduled Firm Capacity Operation Date: The date specified in
Section 2.1.5 as the day upon which the Generating Facility will
be capable of reliably supplying Firm Capacity to the SDG&E
system.
3.38 SDG&E's Electric Department Rule 21: SDG&E's interconnection
standards for cogenerators and small power producers
interconnected with the SDG&E system, in effect on the date of
execution of this Agreement, incorporated as Exhibit F. (Some
portions not applicable to out-of-service area generating
facilities).
3.39 SDG&E Facilities: Facilities owned by SDG&E which are required
for scheduling, metering and operation and for the proper parallel
operation of the Generating Facility with SDG&E's system. These
facilities will include, but not be limited to: connection,
transformation, communication, switching, metering, safety
equipment and any necessary additions and/or reinforcements
required and added by SDG&E to SDG&E's system, excluding any Line
Extension Facilities.
3.40 Small Power Production Facility: A facility which produces
electric energy solely by the use, as a primary energy source, of
biomass, waste, renewable resources, or any combination thereof,
as defined in Title 18 Code of Federal Regulations, Part 292, as
of the date of execution of this Agreement.
3.41 Station Load: Load specifically related to the operation of the
generation auxiliary equipment. Such auxiliary equipment includes,
but is not necessarily limited to, forced and induced draft fans,
cooling towers, boiler feed pumps, lubricating oil systems,
generating facility lighting, fuel handling systems, control
systems, and sump pumps.
3.42 Statement: A written statement setting forth amounts of Energy
and Firm Capacity delivered and sold to SDG&E and amounts due to
Seller for such Energy and Firm Capacity, as more fully described
in Section 15.
3.43 Surplus Energy: The total output of the Generating Facility, less
Station Load and other load requirements of the Seller, that the
Seller actually delivers to the Point of Delivery from the
Generating Facility.
3.44 System Emergency: A condition on SDG&E's system which is likely
to result in imminent significant disruption of service to
customers, or is likely to endanger life or property.
3.45 Three Party Operating Agreement: That Agreement which must be
executed prior to Initial Operation, which will set forth the
terms and conditions for the metering, scheduling and billing, and
ownership and maintenance of facilities, necessary for delivery of
power from an out-of-service area Generating Facility to the SDG&E
system.
3.46 Willful Action:
3.46.1 Action taken or not taken by a Party at the direction of
its directors, officers or supervisory employees affecting its
performance under this Agreement, which action is knowingly or
intentionally directed by such directors, officers or supervisory
employees with conscious indifference to the injurious
consequences thereof, or with intent that injury or damage would
result or would probably result therefrom. Willful Action does
not include any act or failure to act which is merely involuntary,
accidental, or negligent.
3.46.2 Action taken or not taken by a Party at the direction of
its directors, officers or supervisory employees affecting its
performance under this Agreement, which action has been determined
by arbitration award or final judgment or judicial decree to be a
contract breach under this Agreement and which occurs or continues
beyond the time specified in such arbitration award or judgment or
judicial decree for curing such default, or, if no time to cure is
specified therein, occurs or continues thereafter beyond a
reasonable time to cure such default.
3.46.3 Action taken or not taken by a Party at the direction of
its directors, officers of supervisory employees affecting its
performance under this Agreement, which action is knowingly or
intentionally directed by such directors, officers or supervisory
employees with the knowledge that such action taken or not taken
is a contract breach under this Agreement.
4. PROJECT FEE
4.1 No later than the date Seller executes this Agreement, Seller
shall post and thereafter maintain a Project Fee equal to five
dollars ($5) for each kilowatt of Nameplate Rating of the
Generating Facility specified in Section 2.1.1. Seller may not
increase the Nameplate Rating of the Generating Facility after the
date of execution of this Agreement. The Project Fee shall be held
as security for Seller maintaining adequate progress in the
development of the Generating Facility. The Project Fee shall be
established by either an escrow account or by an irrevocable
letter of credit with terms and conditions agreed to by the
Parties. Such escrow account or irrevocable letter of credit
shall provide for the disbursement of the Project Fee in
accordance with Section 4.2.
4.2 The Project Fee shall be disbursed in the following manner on
notice provided to the holding agent by SDG&E.
4.2.1 The Project Fee, including any interest earned, shall be
returned to Seller (a) if the Generating Facility achieves
Reliable Operation prior to the date specified in Section 2.4.6;
(b) if Seller terminates this Agreement as a result of an
Uncontrollable Force prior to Reliable Operation of the Generating
Facility; (c) if Seller determines as a result of either the Line
Loss and Transmission Impact Study or the Detailed
Interconnection/Operation Study that the project is no longer
feasible or that transmission capacity is not available, (Seller
must apply for a refund within ninety (90) calendar days after
receiving written notification of the results of such study.); (d)
if Seller determines that the cost or conditions of obtaininq
transmission rights from the Generating Facility to SDG&E's system
renders the project non-economic, and so notifies SDG&E no later
than 30 days after the date such transmission rights must be
secured under Section 5.5; (e) if the conditions of Section 28 are
not fulfilled and this Agreement is terminated; or (f) if Seller
terminates this Agreement as a result of the CPUC approval
described in Section 28 not having been obtained by November 30,
1990, and Seller notifies SDG&E in writing no later than 30 days
after the actual date of said CPUC decision.
4.2.2 The Project Fee, including any interest earned, shall be
paid to SDG&E in the event Seller fails to complete each and every
project development milestone set forth in Section 5, whether or
not SDG&E pursues any other remedy at law or under this Agreement.
5. PROJECT DEVELOPMENT MILESTONES
5.1.1 The following events shall constitute Project Development
Milestones:
(a) Submit Quarterly Status Reports (Section S.2)
(b) Maintain Site Control (Section 5.3)
(c) Provide information for and pay costs of the Preliminary
Interconnection/Operating Study (Section 5.4).
(d) (For out-of-service area Generating Facilities only) Provide
evidence that Seller has secured acceptable transmission
rights for delivery of Energy and Firm Capacity from the
Generating Facility to the SDG&E Point of Delivery (Section
5.5).
(e) (For out-of-service area Generating Facilities only) Provide
information and pay costs for SDG&E to conduct a Line
Loss/Transmission Impact Study (Section 5.6).
(f) Provide information for and pay costs of the Detailed
Interconnection/Operating Study (Section 5.7).
(g) Commence construction of the Generating Facility (Section
5.8)
5.1.2 If Seller fails to complete each Project Development
Milestone in the time and manner provided in Sections 5.2 through
5.9, SDG&E may terminate this Agreement and Seller shall be liable
for liquidated damages, if any, pursuant to Section 17 of this
Agreement and such other damages as SDG&E may be entitled to. If
SDG&E terminates this Agreement the provision of Sections 5.1.3
and 5.1.4 shall also apply.
5.1.3 If SDG&E terminates this Agreement pursuant to 5.1.2,
Seller may execute another contract with SDG&E only under one of
the other alternative methods described in Section 5.1.4 and only
if the following conditions are satisfied.
(a) Seller provides SDG&E with a new project definition and
provides SDG&E a new project fee in the amount of S5/kw; and
(b) Seller has paid to SDG&E all outstanding obligations arising
under this Agreement including any damages which SDG&E may
have incurred as a result of Seller's failure to perform
under this Agreement. Nothing in this Section 5.1.3 shall
limit SDG&E's remedies at law under this Agreement.
5.1.4 If Seller satisfies the requirements of Section 5.1.3,
Seller may execute a new contract with SDG&E, to sell power from
the Generating Facility, by any of the following alternative
methods:
(a) By fulfilling all the prerequisites for eligibility to
execute and by executing a firm capacity standard offer contract,
if one is available. If Seller elects to sign a then current firm
capacity standard offer contract within two years of the date of
termination of this Agreement by SDG&E, the price for the firm
capacity provided under such contract shall be the lesser of the
then current firm capacity prices specified in the contract or the
Firm Capacity price Seller would have received under this
Agreement.
(b) By fulfilling all the prerequisites for eligibility to
execute and by executing an available long-run standard offer
contract if one is available. However, Seller may not participate
in the next long run standard offer update cycle if such cycle
occurs within two years after the date of termination of this
Agreement by SDG&E.
(c) By fulfilling all the prerequisites for eligibility to
execute and by executing an as available standard offer contract,
if one is available. If Seller signs an as-available standard
offer because no other standard offer agreement is then currently
available, Seller may switch to another standard offer agreement
when one becomes available subject to the conditions of such
standard offer and this Section 5.1.4.
(d) A non-standard agreement subject to the negotiations between
Seller and SDG&E.
5.2 Submit Quarterly Status Reports
5.2.1 Beginning on the first day of the calendar quarter
following the date of execution of this Agreement, and continuing
on the first day of each calendar quarter thereafter until the
Scheduled Firm Capacity Operation Date, Seller shall submit to
SDG&E a complete and accurate Quarterly Status Report in the form
attached as Exhibit D. The Quarterly Status Report shall describe
the progress of project development and shall include without
limitation (a) the current status of and schedule for project
development; (b) Seller's progress since the last submitted
Quarterly Status Report; and (c) an explanation of any changes to
the project development schedule since Seller's last submitted
Quarterly Status Report. If, in SDG&E's judgment, the scheduled
development of the Generating Facility places Seller in jeopardy
of missing a project development milestone under this Section 5,
Seller shall, upon request, provide a summary of the steps which
Seller has taken and proposes to take to ensure timely Reliable
Operation of the Generating Facility.
5.2.2 If Seller fails to provide a Quarterly Status Report in a
timely manner or if Seller fails to submit a complete and accurate
Quarterly Status Report, SDG&E will so notify Seller and Seller
shall promptly provide a complete and accurate Quarterly Status
Report. If Seller fails to provide two consecutive Quarterly
Status Reports as provided in Section 5.2.1, SDG&E shall notify
Seller in writing that Seller has failed to complete this project
development milestone. Unless Seller provides SDG&E with a
complete and accurate Quarterly Status Report within thirty (30)
calendar days after Seller receives such notice from SDG&E, the
provisions of Section 5.1.2 shall apply.
5.3 Maintain Site Control
5.3.1 Seller warrants that it will secure, and provide evidence
to SDG&E that it possesses, Site Control of the site described in
Section 2.1.3 and Exhibit A before March 31, 1990 and that Seller
shall maintain continuous Site Control for the term of this
Agreement. If SDG&E does not receive evidence sufficient to
clearly demonstrate that Seller possesses Site Control consistent
with Section 5.3.2 prior to said date, this Agreement shall
terminate and the provisions of Sections 4.2.2 and 5.1.2 apply.
Seller shall not have additional time to cure this default.
5.3.2 Site Control shall consist of the following, or other form
of Site Control acceptable to SDG&E:
(a) The ownership of the location of Generating Facility
specified in Section 2.1.3;
(b) The leasehold interest in the location specified in Section
2.1.3 which leasehold interest shall specifically include the
right to construct and operate the Generating Facility at such
location;
(c) Seller's exclusive and irrevocable contractual right to
construct and operate the Generating Facility at the location
specified in Section 2.1.3; or
(d) Seller's exclusive and irrevocable option to obtain any of
the rights described in Section 5.3.2 (a) through (c) above. This
alternative shall only constitute Site Control prior to the
commencement of construction of the Generating Facility.
5.3.3 Seller shall provide SDG&E with prompt notice of any change
in the status of its Site Control. If, at any time, SDG&E has
reason to believe that Seller has lost Site Control, SDG&E may
request from Seller evidence that Seller cont- inues to possess
Site Control. If Seller fails to provide such evidence within
thirty (30) calendar days after Seller receives SDG&E's request,
the provisions of Section 5.1.2 shall apply.
5.3.4 Where the term of Seller's Site Control does not extend for
the full term of this Agreement, Seller shall advise SDG&E of the
date Site Control is scheduled to expire. Seller shall provide to
SDG&E, no later than the date Seller's Site Control is scheduled
to expire, evidence that Seller's Site Control has been renewed
or extended. If Seller fails to provide such evidence, SDG&E
shall notify Seller in writing that Seller is not in compliance
with this Section 5.3.4. Unless Seller provides SDG&E with
evidence that Site Control has been renewed or extended within
thirty (30) calendar days after SDG&E's notification, the
provisions of Section 5.1.2 shall apply.
5.3.5 This Agreement is project and site specific; however, with
SDG&E's prior consent, Seller may be permitted to adjust the
location of the Generating Facility within the proximity of the
site specified in Section 2.1.3 if necessary for project
development.
5.4 Provide information for and Pay costs of Preliminary
Interconnection/Operating Study
5.4.1 To the extent that Seller will be interconnected with the
electrical system of Arizona Public Service Company ("APS") and
APS will deliver Seller's generation to the North Gila substation,
this milestone is complete. Otherwise not later than three (3)
months after the effective date of this Agreement or such other
date as the Parties may agree, Seller shall provide SDG&E with the
information necessary for SDG&E to perform a pre- liminary
Interconnection/Operating Study. The Parties shall cooperate to
ensure that Seller provided SDG&E with sufficient information no
later than said date.
5.4.2 Seller shall pay any cost associated with the Preliminary
Interconnection/Operating Study by the date specified in Section
5.4.1 or within thirty (30) calendar days of billing by SDG&E,
whichever is later.
5.4.3 Except for Generating Facilities located out of SDG&E's
Service Area, priority for transmission capacity on the SDG&E
system shall be established on the date Seller has completed the
requirements specified in Section 5.4.1 and 5.4.2.
5.4.4 The results of the Preliminary Interconnection/Operating
Study are for information purposes only, except that in the event
the date determined for providing information for and paying the
cost of the Detailed Interconnection/Operating Study pursuant to
Section 5.5 is earlier than the date specified in Section 2.4.3,
then such earlier date shall establish the milestone date for
this project development milestone pursuant to Section 5.7.1.
5.4.5 SDG&E may, at its discretion, waive the requirements of
this Section 5.4 if SDG&E deems that a Preliminary
Interconnection/Operating Study is unnecessary.
5.4.6 If Seller fails to either (a) provide the information
necessary for SDG&E to conduct the Preliminary
Interconnection/Operating Study or (b) pay the costs of such study
by the date required, SDG&E shall notify Seller in writing that
Seller has not completed this project development milestone. If
Seller fails to provide such information or pay such costs, as the
case may be, within thirty (30) calendar days after SDG&E's
notification, the provisions of Section 5.1.2 shall apply.
5.5 (For out-of-service area Generating Facilities only). Provide
evidence that Seller has obtained accept- able transmission rights
for delivery of Energy and Firm Capacity from the Generating
Facility to the Point of Delivery.
5.5.1 Not later than six (6) months from the date of execution of
this Agreement, Seller shall provide to SDG&E satisfactory
evidence that Seller has obtained rights for firm transmission
service from the Generating Facility to the Point of Delivery.
5.5.2 Such firm transmission rights must be acceptable to SDG&E
in its sole discretion, so as to allow for the proper and safe
delivery of power from the Generating Facility to SDG&E consistent
with the obligations of Seller to provide SDG&E with Firm Capacity
under this Agreement. SDG&E's right to approve the firm trans-
mission rights hereunder shall not entitle it to require terms or
conditions more burdensome than those normally contained in the
standard practices in the utility industry with respect to
interutility firm capacity transactions.
5.5.3 Such firm transmission rights must commence no later than
Initial Operation and must remain in effect for the remaining term
of this Agreement.
5.5.4 If Seller fails to obtain transmission rights acceptable to
SDG&E by the date specified in Section 5.5.1, SDG&E shall notify
Seller in writing that Seller has not completed this project
development milestone. If Seller fails to provide SDG&E with
evidence that acceptable transmission rights have been secured
within thirty (30) calendar days after SDG&E's notification; the
provisions of Section 5.1.2 shall apply.
5.6 (For out-of-service area Generating Facilities Only). Provide
information and pay cost for SDG&E to conduct a Line
Loss/Transmission Impact Study.
5.6.1 To the extent that Seller will be interconnected with the
electrical system of Arizona Public Service Company ("APS")and APS
will deliver Seller's generation to the North Gila substation,
this milestone is complete. Otherwise not later than the date
specified in Section 2.4.4 for conducting the Detailed
Interconnection/Operating Study, Seller shall provide to SDG&E all
information necessary for SDG&E to perform a Line Loss and
Transmission Impact Study. The Parties shall cooperate to ensure
that Seller provides SDG&E with sufficient information no later
than said date.
5.6.2 Seller shall pay any costs associated the Line Loss and
Transmission Impact Study by the date specified in Section 5.6.1
or within thirty (30) calendar days of billing by SDG&E, whichever
is later.
5.6.3 Priority for transmission capacity on the SDG&E system
shall be established on the date Seller completes the requirements
specified in Sections 5.6.1 and 5.6.2. (not applicable to
out-of-service area Generating Facilities).
5.6.4 SDG&E shall complete the Line Loss/Transmission Impact
Study within thirty (30) days after Seller has requested, paid
for and provided all information necessary for SDG&E to conduct
such study. The Line Loss and Transmission Impact Study shall,
among other items, identify any line losses associated with
delivery of Energy and Firm Capacity from the Point of Delivery to
the Designated Point of Interconnection, as well as identify any
impacts of operation of the Generation Facility on SDG&E's
intertie transmission system including those which would restrict
SDG&E's ability to economically accept power along the designating
intertie path.
5.6.5 The results of the Line Loss/Transmission Impact Study
pertaining to rates for transmission losses are for informational
purposes only. Actual rates for losses from the Point of Delivery
to the Designated Point of Interconnection shall be SDG&E's FERC
filed rates, subject to change from time to time and filing with
the appropriate Regulatory Agencies.
5.6.6 If Seller fails either (a) to provide the information
necessary for SDG&E to perform the Line Loss/ Transmission Impact
Study or (b) to timely pay the costs associated with the Line
Loss/Transmission Impact Study, SDG&E shall notify Seller in
writing that Seller has not completed this project development
milestone. If Seller fails to provide such information or pay such
costs, as the case may be, within thirty (30) calendar days after
SDG&E'snotification, the provisions of Section 5.1.2 shall apply.
5.7 Provide information for and pay costs of Detailed
Interconnection/Operating Study
5.7.1 Not later than the date specified in Section 2.4.4, or such
earlier date as may be determined by the Preliminary
Interconnection/Operating Study, Seller shall provide SDG&E with
all information necessary for SDG&E to perform a Detailed
Interconnection/Operating Study. The Parties shall cooperate to
ensure that Seller provides SDG&E with sufficient information no
later than said date.
5.7.2 Seller shall pay any costs associated with the Detailed
Interconnection/Operating Study by the date specified in Section
5.7.1 or within thirty (30) calendar days of billing by SDG&E,
whichever is later.
5.7.3 Subject to Section 5.6. If priority for transmission
capacity on the SDG&E system has not been previously established
in Section 5.4, such priority shall be established on the date
Seller completes the requirements specified in Section 5.7.1 and
5.7.2.
5.7.4 If Seller fails either (a) to provide the information
necessary for SDG&E to perform the Detailed
Interconnection/Operating Study or (b) to timely pay the costs
associated with the Detailed Interconnection/Operating Study,
SDG&E shall notify Seller in writing that Seller has not completed
this project development milestone. If Seller fails to provide
such information or pay such costs, as the case may be, within
thirty (30) calendar days after SDG&E's notification, the
provisions of Section 5.1.2 shall apply.
5.8 Commence construction of the Generating Facility
5.8.1 Seller shall commence construction of the Generating
Facility and shall provide to SDG&E written notice that
construction has commenced not later than the date specified in
Section 2.4.5. Construction of the Generating Facility shall be
deemed to have commenced in accordance with Section 5.8.2. If
Seller fails to commence construction or fails to provide SDG&E
written notice that construction has commenced by the date
specified, SDG&E shall notify Seller in writing that Seller has
not completed this Project Development Milestone. Unless Seller
commences construction and provides SDG&E with written notice of
commencement of construction within thirty (30) calendar days
after SDG&E's notification, the provisions of Section 5.1.2 shall
apply.
5.8.2 Commencement of construction shall be defined as the date
on which Seller initiates continuous work to install major
Generating Facility components such as penstocks, diversion works,
production wells and steam gathering systems, or the placement of
concrete foundations for structures and equipment at the location
of The Generating Facility specified in Section 2.1.3.
5.9 Establish Reliable Operation of the Generating Facility
5.9.1 Seller must establish Reliable Operation of the Generating
Facility by the Scheduled Firm Capacity Operation Date, specified
in Section 2.1.5, subject to the provisions of Section 5.9.2.
5.9.2 If Seller does not establish Reliable Operation of the
Generating Facility by the Scheduled Firm Capacity Operation Date
specified in Section 2.1.5, Seller shall have until the date
specified in Section 2.4.6 to establish Reliable Operation,
subject to the following provisions.
(a) Seller shall submit to SDG&E an updated Status Report for the
Generating Facility, in the form as described in Section 5.2
within 10 days after the Scheduled Firm Capacity Operation Date.
Seller shall submit an updated report every 30 days thereafter
until Seller establishes Reliable Operation of the Generating
Facility. Seller shall include in each report: (i) an update of
the current status of and schedule for project development and
(ii) a summary of the steps which Seller has taken and proposes to
take to ensure that it will be able to establish Reliable
Operation of the Generating Facility by the date required in this
Section 5.9.2. In addition, Seller shall include in the initial
report an explanation of why Reliable Operation did not occur by
the Scheduled Firm Capacity Operation Date.
(b) The price for Firm Capacity shall be that price Seller would
have received under this Agreement, had Seller established
Reliable Operation as of the Scheduled Firm Capacity Operation
Date, according to the options selection in Sections 9.3 and 9.4.
(c) The date specified in Section 2.4.6 shall be delayed one
additional day for each day after June 30, 1990 elapsing until the
CPUC approves this Agreement consistent with Section 28. In no
event shall the date in Section 2.4.6 be delayed beyond June 1,
1995.
5.9.3. The provisions of Section 5.1.2 shall apply if Seller
fails to:
(a) provide Status Reports in a timely manner or to submit
complete and accurate Quarterly Status Reports as prescribed in
Section 5.9.2 or;
(b) establish Reliable Operation of the Generating Facility
within the time required by Sections 5.9.1 and 5.9.2.
6. EFFECTIVE DATE AND TERM
6.1 This Agreement shall be binding upon execution and shall remain in
effect for the number of years specified in Section 2.1.6 from the
later of the Scheduled Firm Capacity Operation Date or the Firm
Capacity Availability Date.
6.2 This Agreement shall terminate if Reliable Operation does not
occur on or before the date specified in section 2.4.6.
7. PURCHASE OF ENERGY
7.1 Payment of Energy shall be based on time of delivery. The time
periods currently in effect are shown in Exhibit B and may be
revised from time to time.
7.2 Beginning with Initial Operation and continuing for the term of
this Agreement, Seller shall sell and deliver and SDG&E shall
purchase and accept, Energy produced from the Generating Facility
up to the Nameplate rating specified in Section 2.1.1, according
to SDG&E's Energy Payment Schedule as updated from time-to-time.
For out-of-service area Generating Facilities all energy
purchased shall be adjusted to reflect losses from the Point of
Delivery to the Designated Point of Interconnection and loses
incurred in delivering energy to the Point of Delivery.
Additionally, Seller shall receive no line loss adjustments or
credits for line losses deemed avoided by on-system Generating
Facilities.
8. METHOD OF PURCHASE AND SALE
8.1 All Energy delivered to SDG&E at the Point of Delivery and
registered by the Meters located thereat shall be provided
according to the option described below and selected in Section
2.3.
8.1.1 Simultaneous Purchase and Sale: Seller shall sell and
deliver to SDG&E the total Generat- ing Facility output, minus
Station Load, to the Point of Delivery. Seller shall purchase
from SDG&E all energy used by Seller for its own consumption.
8.1.2 Sale of Surplus Energy: Seller shall sell and deliver to
SDG&E at the Point of Delivery any Surplus Energy generated by the
Generating Facility. Seller shall purchase from SDG&E any
additional energy required for Seller's own consumption.
8.1.3 Off-System Sales: Seller shall sell to SDG&E at the Point
of Delivery Energy delivered from the Generating Facility less any
losses associated with such delivery of power from the Generating
Facility to the Point of Delivery and from the Point of Delivery
to the Designated Point of Interconnection.
8.2 All Energy delivered to SDG&E by Seller shall be metered according
to time-of-use metering at Seller's expense.
8.3 Seller (except an out-of-service area Seller) shall have the
ability to convert between the options specified in Section 8.1
provided that the Seller gives SDG&E a minimum of sixty (60) days
advance written notice prior to the desired date of such
conversion. Seller may not convert more than once in any 12 month
period. Any and all costs incurred by SDG&E as a result of any
such conversion shall be paid by the Seller within thirty (30)
days of receipt of notice from SDG&E of the amount of such costs.
In addition, the cost of SDG&E Facilities and Line Extension
Facilities upon which the monthly O&M charge is based shall be
adjusted to reflect the costs of such conversion. SDG&E shall not
be required to remove or reserve capacity of the Interconnec- tion
Facilities or Line Extension Facilities made idle by Seller' s
energy sale conversion except as provided in SDG&E's Electric
Department Rule 21 and may use such facilities at any time to
serve other customers or to interconnect with other elec- tric
power sources as provided in SDG&E's Electric Department Rule 21.
8.4 If the option described in Section 8.3 is exercised, then
termination provision (as described in Section 17) shall apply to
the amount by which the Firm Capacity is reduced as a result of
such conversion.
8.5 SDG&E shall process a request by Seller to convert between the
Options specified in Section 8.1 and institute any changes made
necessary by such request as expeditiously as possible given
SDG&E's other resource commitments. The conversion shall be
effective on the date SDG&E notifies Seller that all changes
necessary to accommodate such conversion have been completed.
9. PURCHASE OF CAPACITY
9.1 Payment for Capacity shall be based on time of delivery. The time
periods currently in effect are shown in Exhibit B and may be
revised from time to time.
9.2 Beginning on Initial Operation and continuing until the Scheduled
Firm Capacity Operation Date or the Firm Capacity Availability
Date of the Generating Facility, whichever occurs later subject to
the provisions of this Agreement, Seller shall sell and deliver
and SDG&E shall purchase and accept, as available capacity
produced from the Generating Facility up to the Nameplate Rating
of the Generating Facility specified in Section 2.1.1, according
to SDG&E's As Available Capacity Payment Schedule as updated from
time to time.
9.2.1 For an out-of-area Generating Facility, capacity payments
to Seller shall be adjusted to reflect additional losses from the
Generating Facility to the Point of Delivery and from the Point of
Delivery to the Designated Point of Interconnection.
Additionally, Seller shall receive no line loss adjustments or
credits for any line losses deemed avoided by on-system Generating
Facilities.
9.3 Beginning on the Scheduled Firm Capacity Operation Date or the
Firm Capacity Availability Date of the Generating Facility,
whichever occurs later subject to the provisions of this
Agreement, and continuing for the remaining term of this
Agreement, Seller shall provide and SDG&E shall purchase Firm
Capacity from the Generating Facility to the SDG&E system at the
Point of Delivery in an amount and for a period as specified in
Sections 2.2.1 and 2.1.6 respectively, according to one of the
following options as selected in Section 2.2.2:
Option 1 - Dispatchable
Option 2 - Actually Delivered
9.4 SDG&E shall purchase Firm Capacity based upon one of the following
options as selected by Seller in Section 2.2.3:
Option 1: The Capacity Payment Schedule for Firm Capacity
Qualifying Facilities in effect at the time of
execution of this Agreement attached as Exhibit
C; and
Option 2: The Capacity Payment Schedule for Firm Capacity
Qualifying Facilities in effect as of the
Scheduled Firm Capacity Operation Date of the
Generating Facility.
9.5 If Seller has elected to provide SDG&E Firm Capacity according to
the Dispatchable Option (Option 1), payments for Firm Capacity
under this Agreement shall be calculated as follows:
The monthly payment for Firm Capacity will be one-twelfth of the
product of the Firm Capacity Price (CP) taken from the Firm Capacity Payment
schedule in effect at the time of execution, multiplied by the Firm Capacity
(FC) and the Capacity Bonus Factor (CBF). Hours of curtailment and energy
deliveries during curtailments shall be specifically excluded from the
capacity calculations.
CP = Firm Capacity Price
FC = Firm Capacity (for out-of-service area Generating
Facilities, minus any adjustments for line losses from
the Point of Delivery to the Designated Point of
Interconnection)
CBF = Capacity Bonus Factor (see 9.7)
($) = (1/12) CP x FC x CBF
9.6 If Seller has elected to provide SDG&E with the Firm Capacity
according to the Actually Delivered Option (Option 2), payments
for Firm Capacity under this Agreement shall be calculated as
follows: The monthly payment for Firm Capacity will be the
product of the Period Price Factor (PPF), the Monthly Delivered
Capacity (MDC) and the Capacity Bonus Factor (CBF), plus any
allowable payment for outages due to scheduled maintenance.
($) = PPF x MDC x CBF
The PPF is determined by multiplying the Firm Capacity Price,
taken from the Firm Capacity Payment Schedule in effect on the
date of execution, by the following Al- location Factor (AF):
AF(yr/month) x Firm Capacity Price($/kw-yr)=PPF($/kw-mo)
Summer 0.13801 x =
Winter 0.04428 x =
AF = The factor that allocates the Firm Capacity Price between
summer and winter months. These factors may be changed upon
one year notice from SDG&E.
The MDC is determined as follows:
1) Determine the Performance Factor (P), which is defined as
follows:
P = A (1-L) (P is less than or equal to 1)
C x (B-S) x E
A = Total kilowatt-hours delivered during all on-peak and
semi-peak hours during the month excluding any Energy
associated with generation levels greater than the
Firm Capacity.
L = (for an out-of-service area Seller) The losses,
expressed as a decimal fraction, associated with
delivery of capacity purchased by SDG&E from the Point
of Delivery to the Designated Point of Interconnection
as specified in the Section 2.1.2.
C = Firm Capacity.
B = Total on-peak and semi-peak hours during the month.
S = Total on-peak and semi-peak hours during the month the
Generating Facility is out of service on scheduled
maintenance.
E = 0.8 to reflect a 20% allowance for forced outage.
(2) Determine the Monthly Capacity Factor (MCF), which is
computed using the following expression:
MCF = P x (1.0 - M)
D
M = The number of hours during the month the Generating
Facility is out of service on scheduled maintenance.
D = The number of hours in the month.
(3) Determine the MDC by multiplying the MCF by C:
MDC (kilowatts) = MCF x C
The monthly payment for Firm Capacity is then determined by
multiplying the proper PPF determined above by MDC and CBF.
($) = PPF x MDC x CBF
CBF = Capacity Bonus Factor (See Section 9.7)
9.6.1 Furthermore, the payment for a month in which there is an
outage for scheduled maintenance shall also include an amount
equal to the product of the average hourly capacity payment and
the number of hours of outage for scheduled maintenance in the
month calculated according to the following formula:
Payment = ($) x S
B - S
where ($) is the monthly payment from the second paragraph of
Section 9.6, line 6 and B and S are from paragraph 9.6(1).
9.7 Capacity Bonus Factor. A Seller who actually delivers Firm
Capacity during the on-peak hours of the peak months at a Capacity
Factor of 85%, as defined by the CPUC, is entitled to an incentive
payment. The Capacity Bonus Factor (CBF) will be calculated as
follows:
CBF = ED ( 1-L) (CBF is greater
C x (PP - SP) x .85 than or equal to 1)
ED = Energy delivered during on-peak hours of the peak months.
L = (for an out-of-service area Seller) The losses, expressed as
a decimal fraction, associated with delivery of capacity
purchased by SDG&E, from the Point of Delivery to the
Designated Point of Interconnection as specified in Section
2.1.2.
C = Firm Capacity
PP = On-peak hours in the peak months
SP = Total on-peak hours during the peak months that the
Generating Facility is out of service on Scheduled
Maintenance.
Conditions
(1) Agreement must be in effect and Generating Facility must be
operable for all of the peak months in order that CBF be
calculated.
(2) The CBF for the period October 1 to September 30 will be
determined by the Generating Facility's performance in the
preceding peak months.
(3) CBF will be equal to 1.0 until Seller's peak months data is
available.
(4) During probationary periods CBF will be limited to 1.O.
(5) Hours of curtailment and energy deliveries during
curtailments shall be specifically excluded from the
capacity calculations.
9.8 Minimum Performance Requirements: To receive capacity payments,
the Generating Facility must meet the following requirements:
9.8.1 The amount of Firm Capacity shall be dispatchable by SDG&E
throughout the year (Option 1) or actually delivered to SDG&E for
all of the on-peak hours of the peak months (Option 2). These
months are currently defined as the months of June, July, August
and September, and may be changed upon one year notice by SDG&E.
All Energy generated by the Generating Facility at levels greater
than the amount of Firm Capacity will be specifically excluded
from the Firm Capacity payment calculations. Hours of curtailment
and energy deliveries during curtailments shall be specifically
excluded from the capacity calculations.
9.8.2 If Seller chooses Option 1, the Firm Capacity shall be
dispatchable by SDG&E throughout the year, subject to a maximum 20
percent monthly allowance for Forced Outages and scheduled
maintenance, and also subject to an allowance for up to 45 days
for a major overhaul. Except during the peak months on the SDG&E
system, Seller may accumulate and apply the 20 percent allowance
for Forced Outages for any consecutive three (3) month period.
Dispatchable means that the Generating Facility is operable and is
capable of delivering capacity, and, when called upon, must
deliver at least the amount of capacity requested by SDG&E up to
the full amount of Firm Capacity. Curtailment rights are as
defined elsewhere in this Agreement.
9.8.3 If Seller chooses Option 2, the Firm Capacity must actually
be delivered to SDG&E for all the on-peak hours of all the peak
months, excluding scheduled maintenance and subject to a 20
percent monthly allowance for Forced Outages.
9.9 Failure to meet minimum Performance requirements. If Seller fails
to meet the minimum performance requirements, on a monthly basis,
then the Seller will be placed on a probationary period not to
exceed 15 months, and will be subject to the following:
9.9.1 Under Option 1 (Dispatchable): During the probationary
period, the Seller will continue to receive capacity payments for
the amount of dispatchable capacity available during said period.
During the probationary period, the Seller's monthly payment for
capacity shall be determined by substituting for the Firm
Capacity, the capacity at which Seller would have met the minimum
performance requirements. In any month during the probationary
period that Seller does not meet the minimum performance
requirements at whatever capacity was determined for the previous
month, Seller's monthly payment for capacity shall be determined
by substituting the capacity at which Seller would have met the
minimum performance requirements. If after the expiration of this
period, the Seller has not demonstrated an ability to provide its
amount of Firm Capacity to SDG&E, that capacity shall be derated
and subsequent monthly payments limited to the new amount of
capacity. The amount by which the Seller's capacity is reduced
shall be subject to Section 17 of the Agreement.
9.9.2 Under Option 2 Actually Delivered: During the probationary
period, the Seller shall earn capacity payments for the amount of
capacity actually delivered. If the Seller fails to deliver the
full contract capacity during each of the following year's peak
months, the amount of Firm Capacity shall be derated to the
greater of the Firm Capacity actually delivered when the minimum
requirements are not met, or the amount of Firm Capacity which
would be reasonably likely to be met. The amount by which the
Firm Capacity is reduced shall be subject to Section 17 of the
Agreement.
9.9.3Hours of curtailment and energy deliveries during
curtailments shall be specifically excluded from the capacity
calculations.
9.10 Scheduled Maintenance: Scheduled Maintenance for the Generating
Facility shall be allowed according to the following conditions:
9.10.1 Outage periods for scheduled maintenance shall not exceed
840 hours (35 days) in any 12 month period.
9.10.2 Seller may accumulate unused scheduled maintenance hours
on a year-to-year basis up to a maximum of 1,080 hours (45 days).
This accrued time must be used consecutively and only for major
overhauls.
9.10.3 Major overhauls shall not be scheduled during the peak
months and shall be limited to once every three years.
9.10.4 Scheduled maintenance shall not exceed 30 peak hours
during the peak months.
9.10.5 Seller shall notify SDG&E 24 hours prior to a scheduled
outage of less than one day, one week prior to a scheduled outage
of one day or more (except for major overhauls), and six months
prior to a major overhaul during periods acceptable to both
parties. Agreed upon dates shall not be changed without formal
written notice to SDG&E in accordance with Section 2.6 of this
Agreement.
9.10.6 Capacity payments will continue during allowed outages for
scheduled maintenance.
9.11 Adjustment to Firm Capacity: Firm Capacity as specified in
Section 2.2.1 may be adjusted only under the following conditions:
9.11.1 Seller may increase the amount of Firm Capacity with the
approval of SDG&E and receive payment for the additional capacity
thereafter. A new overall capacity price will be established
based on the original capacity price for the original Firm
Capacity and the applicable capacity price for the remaining term
of this agreement published by SDG&E at the time the increase is
first delivered to SDG&E. This new overall capacity price will be
prorated in proportion to the original Firm Capacity and the
increase in Firm Capacity.
9.11.2 Either Party may request, when it reasonably appears that
the capacity of the Generating Facility may have changed for any
reason, that a new Firm Capacity be determined. If a decrease
occurs that decrease will be subject to Section 17 of the
Agreement.
10. SELLER'S GENERAL OBLIGATIONS
Seller shall:
10.1 Design, own, construct, operate and maintain the Generating
Facility provided that SDG&E shall have the right to require
modifications to such design as provided in Section 11.2.
10.2 Operate and maintain the Generating Facility in accordance with
prudent electrical practices. If a condition is created by Seller
which may unreasonably interfere with the reliability or safety of
operation of the Generating Facility or the SDG&E system, the
Seller shall correct or eliminate such condition with reasonable
diligence.
10.3 Notify SDG&E: (a) by January l, May l and September l of each
year, of the estimated scheduled maintenance and estimated daily
Energy and Firm Capacity for the succeeding four months and (b) by
September 1 of each year, of the estimated scheduled maintenance
and estimated daily Energy and Firm Capacity for the following
year.
10.4 If an in-service area Generating Facility, place its main
disconnect switch under the control of both SDG&E and Seller by
(a) allowing SDG&E to add its lock to Seller's lock on the switch
door, (b) allowing SDG&E to stencil its markings on the switch
door and (c) allowing SDG&E 24-hour access to the switch. Switch
operation shall be reserved exclusively for SDG&E and Seller
personnel, and each Party will be able to lock out the switch.
Switch maintenance shall be performed by Seller's personnel.
10.5 Provide SDG&E by means of a separate, written instrument, any
rights-of-way and access required for construction, operation,
maintenance, inspection and testing of Interconnection Facilities
and testing, reading of Meters and operating of Seller's main
disconnect switch.
10.6 Maintain proper daily Generating Facility operating records,
including, but not limited to fuel consumption, cogeneration fuel
efficiency, kilowatts, kilovars and kilowatt-hours generated and
maintenance performed, and make such records as are reasonably
needed by SDG&E to implement this Agreement available to SDG&E
during normal business hours upon request.
10.7 Provide to SDG&E Generating Facility electrical design and
Interconnection Facilities design drawings for its review prior to
finalizing Generating Facility design and before beginning
construction work based on such drawings. SDG&E may require
modification of such design as provided in Section 11.2.
10.8 Provide to SDG&E reasonable advance written notice of any changes
in the Generating Facility or Interconnection Facilities and
provide to SDG&E design drawings of any such changes for its
review and approval as provided in Section 11.2.
10.9 If an in-service area Generating Facility, test its
Interconnection Facilities at least every 12 months, by qualified
personnel, notify SDG&E at least 72 hours in advance of such tests
and permit SDG&E to have a representative present at such tests.
10.10 If an in-service area Generating Facility, design and operate the
Generating Facility to limit the adverse effects of reactive power
flow on the utility system. Seller shall operate the Generating
Facility in a manner to satisfy the reactive power requirement of
Seller's load within the limit of the Generating Facility's
capability as set forth in SDG&E's Electric Department Rule 21.
10.11 Notify SDG&E of Initial Operation at least forty-five (45) days
prior to such date. SDG&E shall inspect the Interconnection
Facilities within thirty (30) days of receipt of such notice. If
SDG&E concludes in good faith that the Interconnection Facilities
are for any reason unacceptable, SDG&E will notify Seller in
writing within five (5) days of completion of the inspection,
stating the reasons for its determination. Seller shall correct
any deficiencies noted by SDG&E and shall provide SDG&E with the
further right to inspect in accordance with the guidelines set
forth above.
10.12 Notify SDG&E at least fourteen (14) calendar days prior to: (a)
the initial energizing of the Point of Interconnection; (b) the
initial operation of each of Seller's generators; and (c) the
initial testing of Seller's protective apparatus. SDG&E shall
have the right to have a representative present at such times.
10.13 Reimburse SDG&E for the cost of acquiring any property rights
which are determined by SDG&E to be required pursuant to this
Agreement.
10.14 Be liable to SDG&E for any loss of whatever kind which SDG&E
incurs as a result of (a) Seller's failure to obtain or maintain
any necessary permit or approval, including completion of required
environmental studies, necessary for the construction, operation
and maintenance of the Generating Facilities, and (b) Seller's
failure to comply with necessary permits and approvals or with any
applicable law.
10.15 As of Initial Operation and throughout the term of this Agreement,
maintain and operate the Generating Facility to assure that the
Generating Facility meets the requirements of a Qualifying
Facility established as of the date of execution of this
Agreement. Seller warrants that the Generating Facility will meet
the requirements of a Qualifying Facility as defined herein from
Initial Operation throughout the term of this Agreement.
10.16 Comply with the requirements of and design the Generating Facility
consistently with SDG&E Electric Department Rule 21, to the extent
that is clear by the context of a particular provision of Rule 21
that such provision should apply to off-system Generating
Facilities, provided, however that the charge for operation and
maintenance of Line Extension and Interconnection Facilities
specified in Rule 21 is subject to revision from time-to-time as
authorized by the CPUC.
11. SDG&E'S GENERAL OBLIGATIONS
SDG&E shall:
11.1 Operate and maintain its electrical facilities in accordance with
applicable generally accepted practices in the electric utility
industry.
11.2 Have the right to review all Generating Facilities and
Interconnection Facilities specifications and designs submitted by
Seller. SDG&E may require modifications to such specifications
and designs as it deems necessary to allow SDG&E to operate its
system safely and reliably. SDG&E shall notify Seller in writing
of the results of the review of the specifications and designs
submitted by Seller, within thirty (30) days of receipt of such
specifications and designs by SDG&E. SDG&E shall include in its
notification to Seller any flaws or design errors, perceived by
the utility in its review of the material submitted by the Seller.
SDG&E's review of Seller's specifications and designs shall not be
construed as confirming or endorsing the design or as any warranty
of safety, durability or reliability of the Generating Facility or
any of the equipment or the technical or economic feasibility of
the Generating Facility. SDG&E shall not, by reason of such
review or failure to review, be responsible for strength, details
of design, adequacy or capacity of the Generating Facility or
equipment, nor shall SDG&E's acceptance of such specifications or
designs be deemed to be an endorsement of any facility or
equipment. Notwithstanding anything in this Agreement to the
contrary, SDG&E shall not be liable to Seller and Seller shall
indemnify and hold SDG&E harmless from any claim, cost, loss,
damage or liability, including attorney's fees and interest,
in-connection with SDG&E's exercise of its rights under this
Section 11.2.
11.3 Make SDG&E Facilities' records available to Seller upon request as
are needed by Seller to implement this Agreement.
11.4 Make available to Seller any data filed in accordance with CPUC
Decision No. 83-10-093, Ordering Paragraph 5f, as specifically
requested by Seller.
11.5 Make available SDG&E Electric Department rules and other existing
publications governing interconnection, at Seller's request.
12. INTERCONNECTION FACILITIES
12.1 The Parties shall execute a separate Interconnection Facilities
Agreement. The Interconnection Facilities Agreement shall provide
for ownership, construction, operation and maintenance of the
Interconnection Facilities pursuant to SDG&E's Electric Department
Rule 21. For an out-of service area Generating Facility, SDG&E
and Seller shall execute a Three Party Operating Agreement, in
lieu of an Interconnection Facilities Agreement, covering design,
purchase, installation, ownership operation and maintenance of
Interconnection Facilities.
12.2 If an in-service area Generating Facility, SDG&E shall own and
shall be solely responsible for the design, purchase,
installation, operation and maintenance of those Interconnection
Facilities necessary to protect SDG&E's system, employees and
customers from damage or injury arising out of or connected with
the operation of the Generating Facility.
12.3 If an in-service area Generating Facility, SDG&E shall design,
own, operate and maintain the SDG&E Facilities and Line Extension
Facilities required to connect the Generating Facility to SDG&E's
electric system as set forth in the Interconnection Facilities
Agreement and the Three Party Operating Agreement.
12.4 If an in-service area Generating Facility, Seller shall be
allocated existing line capacity in accordance with SDG&E's
Electric Department Rule 21.
12.5 The Parties recognize that from time to time certain improvements,
additions or other changes in the Interconnection Facilities may
be required for the proper and safe operation of the Generating
Facility in parallel with SDG&E's system. SDG&E shall have the
right to make such changes or require Seller to make such changes,
whichever is appropriate, upon reasonable advance written notice
to Seller. Seller shall reimburse SDG&E for all costs incurred by
SDG&E for any additions or changes in the SDG&E Facilities to the
extent required by SDG&E's Electric Department Rule 21 and the
cost of SDG&E Facilities upon which the O&M charge is based shall
be adjusted to reflect the cost of such changes.
12.6 If an in-service area Generating Facility, Seller shall pay for
operation and maintenance of Line Extension and SDG&E Facilities
in accordance with SDG&E's Electric Department Rule 21 and Section
14.2 of this Agreement. Seller shall be solely responsible for
maintaining in good operating condition all Interconnection
Facilities owned by Seller. When the Generating Facility is
generating electrical energy whether or not it is operating in
parallel with SDG&E's system, all Interconnection Facilities shall
be in good repair and proper operating condition.
12.7 For an out-of-service area Seller, Seller shall be responsible for
securing all rights for transmission to the Point of Delivery.
Seller shall also be responsible for securing all interconnection
arrangements with its host utility necessary for the delivery of
power to the Point of Delivery consistent with Seller's
obligations under this Agreement.
13. CANCELLATION CHARGES
Seller shall be responsible for the reimbursement to SDG&E of any and
all cancellation charges incurred as a result of SDG&E cancelling
order(s) for equipment necessary for the interconnection between SDG&E
and Seller, provided that said charges be due to Seller's cancellation
or modification of the Generating Facility. Seller shall pay SDG&E
within thirty (30) days after receipt of notice for said charges.
14. BILLING AND PAYMENT
14.1 SDG&E shall read all Meter(s) monthly according to its regular
meter reading schedule beginning no more than thirty (30) days
after Initial Operation. SDG&E shall mail to Seller not later
than thirty (30) days after the end of each monthly billing period
(a) a Statement showing Energy and capacity delivered to SDG&E
during each of the then currently effective Time-of-Use periods
during the monthly billing period, (b) SDG&E's computation of the
amount due Seller, and (c) SDG&E's check in payment of said
amount. If within thirty (30) days of receipt of the Statement
Seller does not make a report in writing to SDG&E of an error,
Seller shall be deemed to have waived any error in SDG&E's
Statement, computation, and payment, and they shall be considered
correct and complete. SDG&E reserves the right to provide such
Statement concurrently with any Bill to Seller for electric or gas
service provided by SDG&E to Seller in accordance with applicable
Rules of Service. For off-system QFs, the determination of the
amount of Energy and Capacity delivered shall be as specified in
the Three Party Operating Agreement.
14.2 Seller shall pay SDG&E (a) the installed cost of SDG&E Facilities
(to the extent appropriate) and the installed cost of any Line
Extension Facilities, (b) a monthly payment for specified SDG&E
Facilities, if appropriate, (c) a monthly O&M Charge for Line
Extension Facilities and SDG&E Facilities, and (d) a monthly
charge to reimburse SDG&E for leased communication facilities when
required by SDG&E for telemetering the Generating Facility output
all in accordance with SDG&E's Electric Department Rule 21 and
Interconnection/Three Party Operating Agreement. Seller shall pay
SDG&E for such charges within fifteen (15) days of the receipt of
a bill for any such charge.
14.3 If either Party disputes a Statement, payment shall be made as if
no dispute existed, pending resolution of the dispute. If the
Statement is determined to be in error, the amount determined to
be in error shall be refunded by the Party owing, with monthly
interest at a rate equal to that applied to SDG&E's Energy Cost
Adjustment Clause pursuant to Section 9.(j).(4) of SDG&E's
Electric Department Preliminary Statement, or successor CPUC
approved interest rate.
14.4 If either Party disputes a Bill, such dispute shall be resolved in
accordance with SDG&E's applicable Rules of Service.
15. METERING OF ENERGY DELIVERIES
15.1 Metering for electric service to Seller and for Energy purchases
by SDG&E shall be at the Point of Delivery or as specified in the
Three Party Operating Agreement. Metering will be installed which
will measure and record flows in each direction. All the meters
and equipment used for measuring power delivered to SDG&E shall be
located on the side of the Interconnection Facilities selected by
Seller and selected in Section 2.5 or as otherwise specified in
the Three Party Operating Agreement. If Seller selects a metering
location on Seller's side of the Interconnection Facilities the
power recorded as delivered to SDG&E shall be adjusted by applying
the transformer loss compensation factor specified in Section 2.5
to derive the amount of energy and capacity deemed delivered. The
transformer loss compensation factor shall be as agreed to by the
parties or at Seller's election, shall be calculated based on the
measured value of transformer losses from the transformer to be
used. If Seller chooses this latter option, Seller shall pay
SDG&E for the cost of determining this measured value.
15.2 All Meters shall be sealed and the seal shall be broken only by
SDG&E, upon occasions when the Meters are to be inspected, tested
or adjusted.
15.3 SDG&E shall inspect and test all Meters upon their installation
and on its regular testing schedule. If requested to do so by
Seller, SDG&E shall inspect or test a Meter, but the expense of
such inspection or test shall be paid by Seller unless the Meter
is found not to comply with the accuracy specifications found in
SDG&E's Electric Department Rule 18, or any superseding standard.
15.4 If a Meter is in error, Section B of SDG&E's Electric Department
Rule 18, or any superseding standard, shall be applied.
15.5 Seller shall report the hourly and daily Energy recordings to
SDG&E periodically as agreed upon by the Authorized
Representatives. Where the Generating Facility's rated capacity
is greater than 2 Mw, the Generating Facility's output shall be
telemetered to SDG&E's Mission Control Center as specified in
SDG&E's Electric Department Rule 21.
16. CONTINUITY OF SERVICE
16.1 SDG&E shall not be obligated to accept or pay for, and SDG&E may
require Seller to temporarily curtail, interrupt or reduce
deliveries of Energy upon advance notice to Seller, in order for
SDG&E to construct, install, maintain, repair, replace, remove,
investigate or inspect any of its equipment or any part of its
system, or if SDG&E determines that such curtailment, interruption
or reduction is necessary because of a System Emergency, forced
outages on the SDG&E system or its interconnected tie lines,
operating conditions on its system, or compliance with prudent
electrical practices, provided that SDG&E shall not interrupt
deliveries pursuant to this Section solely in order to take
advantage, or to make purchases, of less expensive energy
elsewhere.
16.2 SDG&E shall not be obligated to accept or pay for, and may require
Seller, with a Qualifying Facility with Nameplate Rating of one
megawatt or greater, to temporarily curtail, interrupt or reduce
deliveries of Energy during periods of Minimum Load Condition
where such purchase results in "negative avoided cost" to SDG&E as
such term is defined by the CPUC.
16.3 Notwithstanding any other provision of this Agreement, if at any
time SDG&E determines that either (a) the Generating Facility may
endanger SDG&E personnel, or (b) the continued operation of the
Generating Facility may endanger the integrity of SDG&E's electric
system, SDG&E shall have the right upon notice to Seller, to
disconnect the Generating Facility from SDG&E's system. The
Generating Facility shall remain disconnected until such time as
SDG&E is satisfied that the condition(s) referenced in (a) or (b)
of this Section 16.3 have been corrected.
16.4 Whenever possible, SDG&E shall give Seller reasonable advance
notice of its intent to refuse to purchase Energy under this
Section 16.
16.5 The Parties will coordinate temporary curtailment and interruption
or reduction of deliveries of Energy required for either Party to
construct, install, maintain, repair, replace, remove, investigate
or inspect equipment in its respective electric system.
16.6 Curtailment of out-of-service area Generating Facility
16.6.1 SDG&E may curtail deliveries of Energy from the Generating
Facility , subject to the conditions set forth in this Section.
16.6.2 For purposes of this Section 16.6, each day shall be
considered to begin at midnight (0001 hrs) and end at midnight
(2400 hrs).
16.6.3 In the event an hour of curtailment scheduled pursuant to
this Section 16.6. coincides with scheduled maintenance, such hour
shall be counted as scheduled maintenance for the purposes of this
Agreement.
16.6.4 SDG&E shall designate the type of curtailment as either
Flexible Curtailment or Block Curtailment. SDG&E shall continue
to make Firm Capacity payments for each curtailment hour subject
to the provisions of this Section 16.6. At the time SDG&E gives
notice of a curtailment period, SDG&E shall also provide a
non-binding estimate of its expected Alternative Energy Cost
during the curtailment period. Seller shall be provided a copy of
SDG&E's California Power Pool Economy Energy Transactions log
indicating SDG&E's system decremental value to verify the
Alternative Energy Cost offers. This information is confidential
to SDG&E and Seller shall not provide this information to anyone
without SDG&E's written consent.
16.6.5 To schedule a Flexible Curtailment, SDG&E shall notify
Seller, no later than two (2) hours prior to the start of the
curtailment period, of the hours, duration, and Alternative Energy
Cost for the curtailment period. No later than one-half (1/2)
hour after SDG&E notifies Seller of such curtailment period,
Seller shall notify SDG&E of the level at which Seller will
operate during the curtailment period. If Seller fails to provide
SDG&E such notice within the time required, SDG&E shall limit
Seller's schedule of deliveries during the curtailment period to
the level at which Seller was delivering to SDG&E at the time
notice was due. The price for Energy delivered and accepted by
SDG&E during these periods shall be as described in Section
16.6.8.(b). Each Flexible Curtailment period shall have a
duration of no less than eight (8) consecutive hours.
16.6.6 The maximum amount of Flexible Curtailment in any calendar
year shall be as follows:
Flexible Maximum
Contract Curtailment Number of
Years Hours Curtailments
1 through 9 900 125
10 through 15 1400 125
16 thereafter 2200 150
16.6.7 Each year SDG&E shall notify Seller of SDG&E's intent to
schedule a Block Curtailment within a six month time period. When
SDG&E better evaluates the timing of the Block Curtailment, SDG&E
shall give Seller not less than three weeks notice of the starting
time, duration, and Alternative Energy Cost for the Block
Curtailment. No later than seven (7) days after SDG&E notifies
Seller of such curtailment period, Seller shall notify SDG&E of
the level at which Seller will operate during the curtailment
period. If Seller fails to provide SDG&E such notice within the
time required, SDG&E shall limit Seller's schedule of deliveries
during the curtailment period to the level at which Seller was
delivering to SDG&E at the time notice was due. The price for
Energy delivered and acc- epted by SDG&E during these periods
shall be as described in Section 16.6.8.(b). The amount of Block
Curtailment in any Contract Year shall not exceed one 400 hour
block or two 200 hour blocks.
16.6.8 During each hour of Flexible or Block Curtailment,
payments shall be made based on the following:
a) Firm Capacity payments shall be made in accordance with
Section 16.6.11.
b) Payments for Energy which Seller has opted to continue to
deliver and provided proper notice of such election in
accordance with Sections 16.6.5 and 16.6.7 shall be
purchased by SDG&E at the Alternative Energy Cost.
c) In the event that the output of the Generating Facility
during any curtailment hour exceeds the level of scheduled
deliveries, pursuant to Sections 16.6.5 and 16.6.7, Seller
shall not be paid by SDG&E for any Energy in excess of such
scheduled amount during such curtailment hour(s).
16.6.9 Nothing in this Section 16.6 is intended to provide Seller
the right, either expressed or implied, to deliver energy to SDG&E
in amounts greater than that designated in Section 2.2.1.
16.6.10 The maximum Energy price paid under this Section 16.6 may
not exceed the applicable time differentiated price for a
non-curtailment hour as provided in Sections 7 and 8.
16.6.11 During hours of curtailment designated under this Section
16.6, SDG&E shall continue to make Firm Capacity payments. Under
Option 1, hours of curtailment and energy deliveries during
curtailments shall be specifically excluded from the capacity
calculations. Under Option 2, for each curtailment hour, payments
shall be made pursuant to the following: (i) payments to Seller
for firm capacity during each on-peak or semi-peak curtailment
hour shall be calculated using Assumed Production Factors derived
from Seller's historical performance pursuant to Section 16.6.12,
provided, that payments for firm capacity calculated using the
Assumed Production Factors shall not exceed the maximum payments
provided under Section 9, (ii) nothing in this Section 16.6 shall
be construed to entitle Seller to payments for Firm Capacity prior
to the Firm Capacity Availability Date, (iii) no firm capacity
payment adjustments are applicable for curtailments during
off-peak and super offpeak hours since no firm capacity payments
are earned during those periods.
16.6.12 Assumed Production Factors a) Subject to the provisions
of Sections 16.6.4, 16.6.5 and 16.6.6, during periods of
curtailment SDG&E shall pay Seller firm capacity payments, as
appropriate, calculated using Assumed Production Factors derived
from Seller's historical performance during the on-peak and
semi-peak time periods during the previous calendar year. The
Assumed Production Factors shall be calculated as follows:
APFs = summer kwhp = summer kwhsP
C x (summer Hp + Summer Hsp)
APFp = summer kwhp
C x summer Hp
where:
APFs = Assumed Production Factor for the summer months for
the combined on-peak and semi-peak periods.
APFp = Assumed Production Factor for the summer on-peak
period
Summer Kwhp, summer kwhsp = the respective on-peak and semi-peak
Energy (kwh) purchased by SDG&E during the previous calendar
year's summer billing period excluding any energy purchased during
periods of Curtailment.
Summer Hp, summer Hsp = the respective on-peak and semi-peak hours
during the previous calendar year's summer billing period
excluding scheduled maintenance hours and curtailment hours under
Section 16.
APFw = winter kwhp +winter kwhsp
C x (winter Hp + winter Hsp)
APFw = Assumed Production Factor for the winter months for
the combined on-peak and semi-peak periods winter
kwhp, winter kwhsp = the respective on-peak and
semi-peak Energy purchased by SDG&E during the
previous calendar year's winter billing period,
excluding any Energy purchased during periods of
curtailment.
C = Firm Capacity
Winter Hp, winter Hsp = the respective on-peak and semi-peak hours
during the previous calendar year's winter billing period
excluding scheduled maintenance and any curtailment hours under
Section 16.
b) During the first twelve (12) monthly billing cycles following
Initial Operation, the Assumed Production Factors shall be
calculated based on cumulative available monthly billing data.
After the first twelve (12) months and until a full calendar
year's billing data is available, the Assumed Production Factors
shall be calculated using the most recent twelve (12) monthly
billing cycles available.
c) During any billing month in which a curtailment period has
occurred during the peak or semipeak time periods under Section
16.6, Firm Capacity payments and Bonus Payments made by SDG&E to
Seller shall be made as follows:
(1) The formula for calculation of Performance Factor (P) as
defined in Section 9.6 shall be revised as follows:
P = Aasm(1-L) P is less than or
C x (B-S) x E equal to 1
where Aasm replaces A and where: Aasm = the sum of the total
kilowatt-hours delivered during all on-peak and semi-peak hours
excluding any kilowatt-hours delivered during hours of curtailment
and excluding any Energy associated with generating levels
greater than the Firm Capacity, plus the kilowatt-hours associated
with the applicable Assumed Production Factor for the combined
time period(s) in which curtailment hour(s) occurred. The
kilowatt-hours associated with the Assumed Production Factor shall
be calculated by multiplying the appropriate APF times the Firm
Capacity times the hours in the on-peak and semi-peak hours in
which curtailment was invoked during the monthly billing cycle.
2) The formula for calculation of the Capacity Bonus Factor (CBF) as
defined in Section 9.7 shall be revised as follows:
CBF = EDasm (1-L) CBF is greater than
C x (PP-SP) x .85 equal to 1
where EDasm replaces ED
and where:
EDasm = the sum of the Energy delivered during the on-peak hours
of the peak months excluding any Energy delivered during hours of
Curtailment, plus the kilowatt hours associated with the Assumed
Production Factor calculated for the summer months. The kilowatt
hours associated with the Assumed Production Factor shall be
calculated by multiplying the APFp times the Firm Capacity times
the number of summer on-peak hours in which curtailment was
invoked during the billing cycle.
16.6.13 During hours of curtailment designed under this section
16.6, Seller shall have the right to sell such curtailed energy to
a third party. It is Seller's obligation not to sell the
curtailed energy on a firm basis. If Sell has elected to sell
energy to a third party during curtailment period, SDG&E shall
have the right to recall such energy for delivery to SDG&E during
such curtailment period upon giving Seller one (1) hour prior
notice of its desire to suspend curtailment. SDG&E will only
suspend curtailment if circumstances change the assumptions
underlying the scheduling of the curtailment. Seller shall use
its best efforts to recommence deliveries to SDG&E should SDG&E
suspend curtailment prior to the time such curtailment period was
scheduled to end.
17. DEFAULT AND REMEDIES
17.1 If either Party defaults in the due performance or observance of
any term or condition of this Agreement, said Party shall be in
default. Upon the occurrence of any default and at any time
thereafter so long as the same shall be continu- ing, the
non-defaulting Party may, by notice to the defaulting Party
specifying the nature of such default, declare this Agree- ment to
be in default. The defaulting Party must remedy such default
within the time specified in this Agreement, or, if no time is
specified, within thirty (30) days after receiving written notice
from the non-defaulting Party. In the event that the defaulting
Party fails to cure its default within such period of time, the
non-defaulting Party may at any time thereafter exe- rcise, at its
election, any rights or remedies it may have under this Agreement,
at law or in equity to enforce the terms hereof, including, but
not limited to, monetary damages, injunctive rel- ief, specific
performance and termination of this Agreement.
17.2 Nothing in this Agreement is intended to limit SDG&E's right to
demand and Seller's obligation to provide adequate assurance in
the circumstances described in the Uniform Commercial Code. The
Parties specifically intend that such rights and obligations shall
exist whether or not the Uniform Commercial Code otherwise
applies.
17.3 Liquidated Damages: Seller agrees to pay SDG&E in event of
Seller's default, as Liquidated Damages and not as a penalty, the
amount calculated pursuant to this Section 17. The Parties agree
that said calculations represent a reasonable endeavor to estimate
fair compensation for SDG&E's foreseeable losses associated with
Seller's failure to deliver Firm Capacity that might result from
Seller's default or from a reduction in Firm Capacity under this
Agreement. The amount of Seller's Liquidated Damages payment shall
be reduced by the Project Fee, if any, paid to SDG&E pursuant to
Section 4 of this Agreement; provided, however, if the amount of
Seller's Liquidated Damages payment is less than the Project Fee
paid to SDG&E pursuant to Section 4 of this Agreement, Seller
shall not be entitled to a refund of the Project Fee or any
portion thereof. This Section 17 shall not preclude or limit
SDG&E's entitlement to monetary damages for losses other than for
failure to deliver Firm Capacity or resulting from other events of
Seller's default.
17.4 In the event of default, SDG&E shall bill Seller for all amounts
due under this Agreement including the amounts calculated in
Section 17. Seller shall pay interest on all amounts due from the
date of notice of default, compounded monthly, at an interest rate
equal to the lower of (a) the maximum rate allowed by law, or (b)
one-twelfth of the most recent month's interest rate on Commercial
Paper (prime, three months) published in the Federal Reserve
Statistical Release, G.13, (or if such publication is no longer
being issued, the closest similar publication), plus 50 basis
points (See Exhibit E). Seller shall pay SDG&E within thirty (30)
calendar days of receipt of SDG&E's bill.
17.5 The non-defaulting party shall have the right to offset any
amounts due it from the defaulting party against any present or
future payments it owes to the defaulting party and may at all
times pursue any other remedies available to it.
17.6 For purposes of this Section 17, "Termination Payment A" shall
mean an amount equal to the difference between payments for Firm
Capacity to date based on the original Agreement length and
payments that would have been made, based upon the period of
Seller's actual performance, up to the date of reduction or
termination, plus interest as set forth in Section 17.4.
17.6.1 If Seller terminates this Agreement, or all or part of the
Firm Capacity stated in Section 2.2.1 with the following
prescribed written notice:
Amount of Capacity
Terminated Length of Notice
Under 5,000 kw 12 months
5,000 kw to 10,000 kw 36 months
10,000 kw to 20,000 kw 48 months
20,001 kw and over 60 months
Seller shall refund to SDG&E Termination Payment A as described in
Section 17.6. SDG&E shall then make capacity payments to Seller
for the remainder of Seller's perfor- mance, if any, at an
adjusted capacity price.
17.6.2 If Seller terminates this Agreement, or all or part of the
Firm Capacity stated in Section 2.2.1, without the notice
prescribed in Section 17.6.1, Seller shall pay SDG&E "Termination
Payment B". Termination Payment B shall consist of the sum of (a)
Termination Payment A and (b) a one-time payment. The one-time
payment shall be equal to the amount of Firm Capacity being
terminated times the difference between the Current Capacity Price
on the date of termination for a term equal to the balance of the
term of the Agreement and the Firm Capacity price. This product
shall be pro-rated for the length of notice given, if any, by
taking the difference between the amount of months of notice
prescribed minus the amount of months of notice given and dividing
by twelve (See Exhibit E, Example 2). In the event that the
Current Capacity Price is less than the Firm Capacity price or the
termination or reduction is a result of an uncontrollable force on
the part of the Seller, then only Termination Payment A shall
apply.
18. ABANDONMENT
18.1 If, in any six (6) month period after the Firm Capacity
Availability Date, Seller fails to deliver to SDG&E at least the
number of kilowatt hours derived from the product of four hundred
and thirty-eight (438) hours times the Firm Capacity rating
measured in kilowatts, Seller shall provide to SDG&E all of the
following:
18.1(a) a written description of the reason for Seller's low
level of performance;
18.1(b) a summary of the action Seller is taking to improve its
performance; and
18.1(c) a schedule for bringing Seller's deliveries up to the
Firm Capacity rating.
18.2 In any fifteen (15) month period after the Firm Capacity
Availability Date, Seller shall deliver to SDG&E not less than the
number of kilowatt hours derived from the product of one thousand
and ninety-five (1,095) hours times the Firm Capacity rating
measured in kilowatts. If, for any reason, Seller fails to
deliver this minimum amount, SDG&E may terminate this Agreement on
written notice. Unless excused as a result of an Uncontrollable
Force, such failure shall constitute a default, entitling SDG&E to
its remedies at law and under Section 17 of this Agreement.
19. NONDEDICATION OF FACILITIES
Seller does not hereby dedicate any part of the Generating Facility to
serve SDG&E, its customers, or the public. SDG&E does not hereby
dedicate any part of its system or facilities to serve or accept Energy
and Firm Capacity from Seller to any greater extent than may be provided
by law.
20. LIABILITY
20.1 Except in the case of Willful Action or sole negligence, neither
Party shall hold the other Party, its officers, agents or
employees liable for any loss, damage, claim, cost, or expense for
loss or damage to property, or injury or death of persons, which
arises out of the other Party's ownership, operation or
maintenance of facilities on its own side of the Point of
Delivery.
20.2 Except as set forth in Section 20.1, each Party agrees to defend,
indemnify and save harmless the other Party, its officers, agents,
and employees against all losses, claims, demands, costs, or
expenses for loss of or damage to property, or injury or death of
persons, which directly or indirectly arise out of the
indemnifying Party's performance pur- suant to this Agreement;
provided, however, that a Party shall be solely responsible for
any such losses, claims, demands, costs or expenses which result
from its sole negligence or Willful Action.
21. INSURANCE
21.1 Seller, at its own expense, shall secure and maintain in effect
during the life of this Agreement the following insu-rance as will
protect Seller and SDG&E during the performance of operation
hereunder:
21.1.1 General Liability Insurance with a combined single limit
for bodily injury and property damage of not less than (a)
$1,000,000 each occurrence if the Generating Facility is 100 kw or
greater; (b) $500,000 each occurrence if the Generating Facility
is between 20 kw and 100 kw; and (c) $100,000 each occurrence if
the Generating Facility is 20 kw or less. Such General Liability
Insurance shall include coverage for Premises-Operations, Owners
and Contractors Protective, Products/Completed Operations Hazard,
Explosion, Collapse, Underground, Contractual Liability, and Broad
Form Property Damage including Completed Operations.
21.1.2 The liability insurance specified in Section 21.1.1 shall
name SDG&E as additional insured and shall contain a severability
of interest or cross-liability clause. The requirement to name
SDG&E as additional insured shall be waived if such requirement
prevents Seller from obtaining insurance as specified herein.
21.2 Certificates of Insurance evidencing the coverages and provision
as required in Sections 21.1.1 and 21.1.2 above shall be furnished
to SDG&E prior to interconnected operation of the Generating
Facility and shall provide that written notice be given to SDG&E
at least thirty (30) days prior to cancellation or reduction of
any coverage. SDG&E shall have the right, but not the obligation,
to inspect the original policies of such insurance. Seller will
not be allowed to commence interconnected operations unless
evidence of satisfactory insurance has been provided to SDG&E in a
timely manner. SDG&E will allow Seller to self-insure in lieu of
compliance with the requirements of Section 22.1 under the
following conditions:
21.3.1 Seller must be a governmental agency with an established
record of self-insurance.
21.3.2 Seller must provide to SDG&E at least thirty (30) days
prior to the Operation Date evidence of an acceptable plan to
self-insure to a level of coverage equivalent to that required
under Section 22.1
21.3.3 If Seller ceases to self-insure to the level required
hereunder, or if Seller is unable to provide continuing evidence
of Seller's ability to self-insure, Seller shall immediately
obtain the coverage required under Sections 21.1.
22. UNCONTROLLABLE FORCE
Neither Party shall be considered to be in default with respect to any
obligation hereunder, other than the obligations to pay money, if
prevented from fulfilling such obligation by reason of an uncontrollable
force. The term "uncontrollable force" means unforeseeable causes,
other than Forced Outages, beyond the reasonable control of and without
the fault or negligence of the Party claiming uncontrollable force,
including but not limited to, acts of God, labor disputes, sudden
actions of the elements, actions by any legislative, judicial or
regulatory agency which conflict with the terms of this Agreement, and
actions by federal, state, municipal, or any other government agency.
Whichever Party is rendered unable to fulfill any obligation by reasons
of uncontrollable forces shall give prompt written notice of such fact
to the other Party and shall exercise due diligence to remove such
inability with all reasonable dispatch. Nothing in this Agreement shall
require a Party to settle any strike or labor dispute in which it is
involved.
23. NON-WAIVER
None of the provisions of this Agreement shall be considered waived by
either Party except when such waiver is given in writing. The failure
of either Party to insist in any one or more instances upon strict
performance of any of the provisions of this Agreement or to take
advantage of any or its rights hereunder shall not be construed as a
waiver of any such provisions or the relinquishment of any such rights
for the future, but the same shall continue and remain in full force and
effect.
24. SUCCESSORS & ASSIGNS
24.1 This Agreement shall be binding upon and inure to the benefit of
the respective successors and assigns of the Parties.
24.2 Neither Party shall voluntarily assign its rights nor delegate its
duties under this Agreement, or any part of such rights or duties,
without the written consent of the other Party, except in
connection with the sale or merger of a substantial portion of its
properties. Any such assignment or delegation made without such
written consent shall be null and void. Consent for assignment
will not be withheld unreasonably. Such assignment shall include,
unless otherwise specified therein, all of Seller's rights to any
refunds which might become due under this Agreement.
25. EFFECT OF SECTION HEADINGS
Section headings appearing in this Agreement are inserted for
convenience only, and shall not be construed as interpretations of text.
26. GOVERNING LAW
This Agreement shall be interpreted, governed, and construed under the
laws of the State of California as if executed and to be performed
wholly within the State of California.
27. SEVERAL OBLIGATIONS
Except where specifically stated in this Agreement to be otherwise, the
duties, obligations and liabilities of the Parties are intended to be
several and not joint or collective. Nothing contained in this Agreement
shall ever be construed to create an association, trust, partnership, or
joint venture or impose a trust or partnership duty, obligation or
liability on or with regard to either Party. Each Party shall be
individually and severally liable for its own obligations under this
Agreement.
28. CONDITIONS
28.1 This Agreement, other than Section 28, and Sections 4.1, 4.2.1,
4.2.2, and 5.3, is contingent on SDG&E obtaining an order from the
CPUC that (i) SDG&E's payments made to Seller under this Agreement
are recoverable, through SDG&E's Energy Cost Adjustment Clause,
subject to review of the reasonableness of SDG&E's performance
under the Agreement, and-(ii) this Agreement is reasonable and
SDG&E's entering into this Agreement is prudent. SDG&E will use
best efforts and Seller shall provide such reasonable assistance
as SDG&E may request in order to expedite obtaining such approval.
Both Parties shall evaluate whether the CPUC has approved this
Agreement based upon the above criteria. To the extent that the
CPUC imposes conditions in its decision which increase either
Party's risk in any respect beyond that which would be present, in
the reasonable judgement of such Party, had the CPUC merely made
the order specified in (i) and (ii) above, such Party may notify
the other that the Agreement has not been Approved by the CPUC.
Within ten (10) days of both Parties' receipt of the CPUC
decision, each Party shall notify the other in writing of its
determination that the decision (a) approves this Agreement, or
(b) does not approve this Agreement, based on the criteria above.
If either Party determines that the CPUC decision does not approve
this Agreement, the Parties shall meet forthwith to modify the
Agreement in a manner to preserve its economic integrity, and
resubmit it to the CPUC, unless the Parties deem it unnecessary
and provide written notice to each other consistent with this
Section 28.1.
28.2 Upon both Parties' providing notice to the other that this
Agreement has been approved by the CPUC, the condition set forth
in Section 28.1 shall be deemed fulfilled.
IN WITNESS WHEREOF, the Parties have caused Agreement to be executed in their
respective names, in duplicate by their respective official representatives as
of the day and year last written below.
By /s/ Robert A. Keegan
(Dated) Robert A. Keegan
Vice President - Development
Bonneville Pacific Corporation
By /s/ Donald E. Felsinger
(Dated) Donald E. Felsinger
Vice President - Marketing
and Resource Development
San Diego Gas & Electric Company
EXHIBIT A
SITE LOCATION METES AND BOUNDS DESCRIPTION
A parcel of property located within the South One-Half of the South one-Half
of the North One-Half (N 1/2, N 1/2) of Section Thirty-Three (33), Township
Sixteen South (T16S), Range Twenty-Two East (R22E), San Bernardino Base and
Meridian (SBBM), Yuma County, Arizona. Said parcel being more particularly
described as follows: Commencing at the Southwest Corner of the Northwest
Quarter of the Northeast Quarter (NW 1/4, NE 1/4), of Section Thirty-Three
(33); Thence N00 14'37"E a distance of 417.42 feet to a point, said point
being the TRUE POINT OF BEGINNING; Thence N00 14'37'E a distance of 538.56
feet to a point; Thence S89 58'54"W a distance of 464.64 feet to a point;
Thence N00 06'31''E a distance of 854.69 feet to a point; Thence S80 13'33"E a
distance of 471.47 feet to a point; Thence S00 00'30"W a distance of 5.07 feet
to a point; Thence S80 13'33"E a distance of 1038.46 feet to a point; Thence
S00 07'26"W a distance of 562.89 feet to a point, said point being the
beginning of a curve to the left with a radius of 60.00 feet, a central angle
of 250 31'44", a chord bearing of 854 51'34"W and a chord length of 97.98
feet; Thence 262.35 feet along the arc of said curve to a point, said point
being the beginning of a curve to the right with a radius of 30.00 feet and a
central angle of 70 31'44"; Thence 36.93 feet along the arc of said curve to a
point; Thence S00 07'26"W a distance of 652.11 feet to a point, said pint
being the beginning of a curve to the right with a radius of 170.00 feet and a
central angle of 11 28'43"; Thence 34.06 feet along the arc of said curve to a
point; Thence S11 36'06"W a distance of 60.31 feet to a point said point being
the beginning of a curve to the left with a radius of 230.00 feet and a
central angle of 11 28'43"; Thence 46.07 feet along the arc of said curve to a
point; Thence S00 07'26"W a distance of 35.50 feet to a point, said point
being the beginning o a curve to the right with a radius of 25.00 feet and a
central angle of 89 51'28"; Thence 39.21 feet along the arc of said curve to a
point; Thence S89 58'54"W a distance of 711.95 feet to a point; Thence N00
14'37"E a distance of 367.42 feet to a point; Thence S89 58'54"W a distance of
208.71 feet to a point, said point being the TRUE POINT OF BEGINNING.
EXHIBIT B
TIME PERIODS
The Time Periods currently in effect for San Diego Gas & Electric are defined
in accordance with the following table:
Summer Winter
May 1 - September 30 All Other
On-Peak 11 a.m.-6 p.m. Weekdays 5 p.m.-8 p.m. Weekdays
Semi-Peak 6 a.m.-11 a.m. Weekdays 6 a.m.-5 p.m. Weekdays
6 p.m.-10 p.m. Weekdays 8 p.m.-10 p.m. Weekdays
Off-Peak 10 p.m.-Midnight Weekdays 10 p.m.-Midnight Weekdays
5 a.m.-6 a.m. Weekdays 5 a.m.-6 a.m. Weekdays
5 a.m.-Midnight Weekends 5 a.m.-Midnight Weekends
5 a.m.-Midnight Holidays 5 a.m.-Midnight Holidays
Super
Off-Peak Midnight-5 a.m All days Midnight-5 a.m. All days
All time periods listed are clock time.
The holidays specified are: New Year's Day, President's Day, Memorial Day,
independence Day, Labor Day, Veteran's Day, Thanksgiving Day and Christmas Day
as designated by California Law.
The time period definitions may be revised to comply with CPUC orders
regarding billing hours.
The energy payments currently are calculated and published four times a year
in accordance with the following table:
Effective Date Applicable Period
February 1 February 1-April 30
May 1 May 1-July 31
August 1 August 1-October 31
November 1 November 1-January 31
EXHIBIT C
Date 09 Mar 89 TABLE 1
SAN DIEGO GAS & ELECTRIC COMPANY
CAPACITY PAYMENT SCHEDULE
FOR
FIRM CAPACITY QUALIFYING FACILITIES
182 MW BLOCK OF SO-2 QFS
DOLLARS/KW-YR
<TABLE>
<CAPTION>
SCHEDULED FIRM
CAPACITY OPERATING DURATION OF CONTRACT (YEARS)
DATE 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1988 65 37 82 32 35 41 46 52 54 57 60 62 64 67 69
1989 5 7 18 25 35 42 47 51 55 59 61 64 67 69 71
1990 9 25 33 44 52 57 62 65 69 72 74 77 79 81 83
199 43 48 59 66 71 74 78 81 83 86 88 90 92 95 96
1992 53 69 75 80 83 86 89 91 94 96 98 100 103 105 106
1993 86 88 91 93 95 98 100 102 104 106 108 111 113 115 116
SCHEDULED FIRM
CAPACITY OPERATING DURATION OF CONTRACT (YEARS)
DATE 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1988 70 72 74 76 77 79 80 81 83 84 85 86 87 88 89
1989 73 75 77 79 80 82 83 85 86 87 89 90 91 92 93
1990 85 87 89 91 92 94 95 97 98 99 101 102 103 104 105
1991 98 100 102 104 105 107 108 110 111 112 114 115 116 117 118
1992 108 110 112 114 115 117 118 120 121 123 124 125 127 128 129
1993 118 120 122 124 125 127 129 130 132 133 135 136 137 138 140
</TABLE>
EXHIBIT D
QUARTERLY STATUS REPORT
QFID No.
Name of Seller
Date
Directions: A complete and accurate response is required each time this
report is filed with SDG&E. Responses of "not appli- cable" or "N/A" must be
supported by a detailed factual explanation for clarification purposes. If
Forecast Completion Date has not been established, so state and explain.
Forecast Check if
(or actual) Schedule
Completion Check if Change from
Date (1) Completed Previous Report
Milestone
Site Control
(a) Proof provided to
SDG&E / / / /
(b) Current site control
status:
_____ Project has site control
_____ Project does not have site control
Critical Path Permit (2)
(a) Permit application
filed / / / /
(b) Permit application
accepted / / / /
(c) Permit issued / / / /
Fuel Supply Status: (e.g., contract signed. resource evaluation studies
complete. etc.)
Financing Secured
(a) Construction (short-
term) / / / /
(b) Permanent (long-
term) / / / /
Forecast Check if
(or actual) Schedule
Completion Check if Change from
Date (1) Completed Previous Report
Final Method of Service
Study Requested / / / /
Equipment Contract Award
(a) Generator / / / /
(b) Turbine/prime mover / / / /
Equipment Ordered
(a) Generator / / / /
(b) Turbine/prime mover / / / /
Engineering/Design
(a) Preliminary
Engineering % Complete
(b) Final Engineering % Complete
Construction Contract
Awarded / / / /
Interconnection Construction
(a) Seller construction
started / / / /
(b) SDG&E construction
requested / / / /
Project Construction
(a) Site grading started / / / /
(b) Major foundations
started / / / /
(c) Turbine/prime mover
on site / / / /
(d) Generator on site / / / /
(e) Construction status % Complete
Forecast Check if
(or actual) Schedule
Completion Check if Change from
Date (1) Completed Previous Report
Initial Parallel
Operation / / / /
Start-up testing begun / / / /
(a) Testing status % Complete
Firm (or As-Available)
Capacity Availability
Date / / / /
Describe progress of project development since the last submitted Quarterly
Status Report (attach additional pages, if needed):
Explain any changes to the project development schedule since last submitted
Quarterly Status Report (attach additional pages, if needed):
I certify that the foregoing information is true and complete.
Date
Signature
Name
Title
Contact Person
Telephone Number
Notes: (1) Should reflect project's current schedule for Milestones not yet
completed or actual completion date for Milestone completed. (2) The
Critical Path Permits for all non-thermal projects and thermal projects exempt
from CEC Site Certification are (i) for Geothermal, County Conditional Use
Permit or Special Zone Permit; (ii) for Biomass, County Conditional Use Permit
or Special Zone Permit, or Air Quality Permit; (iii) for Wind, County
Conditional Use Permit or Special Zone Permit; (iv) for Cogeneration, Air
Quality Permit; (v) for Hydro, FERC License or Exemption. California Energy
Commission Site Certification is required for non-exempt thermal projects over
50 MW.
EXHIBIT E
REDUCTION AND TERMINATION
PAYMENT EXAMPLE
These examples are for demonstration purposes only and should not be
construed as a projection of SDG&E Actual Termination Payments.
Example 1:
Termination with 36 months written notice given 12 years after the
Operation Date for termination 15 years after the Operation Date or on
December 31, 1999.
Assumptions for this example:
Contract Capacity - 10 megawatts (10,000 kilowatts)
Contract Term - 25 years
Operation Date - January 1, 1985
Contract Capacity Price - $115 per kilowatt per year
Monthly Interest Rate - 1% per month (assumed to be constant)
(a) Total Capacity Payment made = $115/kW-yr x 10,000 kw = $1,150,000 per
year
(b) Total Capacity Payments which would have been made for a 15 year
Contract Term = $100/kW-yr x 10,000 kw = $l,000,000 per year.
(c) The difference between (a) and (b) of annual overpayments = $1,150,000 -
$l,000,0000/yr = $150,000/yr
Termination Payment A is then the value at the end of the 12th year of the sum
of the annual overpayments multiplied by a one (1%) percent per month interest
charge.
Termination Payment A:
$150,000/yr x 1 yr/12 months x (Compound Amount Factor at 1% per month for 12
years) = $3,988,269.
SDG&E would then pay QF $100/kW-yr for the remaining 36 months of revised
contract term.
Example 2:
Termination without prescribed notice 12 years after the Operation Date
or on December 31, 1997.
Assumption for this Example:
Contract Capacity - 10 megawatts
(10,000 kilowatts)
Contract Term - 25 years
Operation Date - January 1, 1985
Contract Capacity Price - $115 per kilowatt per year
Monthly Interest Rate - 1% per month (Assumed to be
constant)
Length of Notice Given - 3 months
Termination Payment B is equal in the sum of Termination Payment A (using the
same methodology as in Example 1 above), and a one-time payment, as follows:
Termination Payment A
(a) Total Capacity Payment made = $115/kW-yr x 10,000 kw
= $l, 150,000/yr
(b) Total Capacity Payment which would have been made using the same
Capacity Payment Schedule in effect at the time of execution for a 12
year contract term = $93/kW-yr x 10,000 kw = $930,000/yr
(c) The difference between (a) and (b), of overpayment $1,150,000 - $930,000
= $220,000/yr
Termination Payment A is then the value at the end of the 12th year of the sum
of the annual overpayments multiplied by one (1%) percent per month interest
charge.
Termination Payment A:
= $220,000/year x 1 year/12 months x (Compound Amount Factor at 1%
month for 12 years) = $5,849,460
One Time Payment
The payment can be formulated as follows: = (Amount of Firm Capacity
Terminated) x (Current Capacity Price - Firm Capacity Price) x (Amount
of Notice Prescribed - Amount of Notice Given)
12 months/year
= (10,000 kW)(200 S/kW-yr - 115 $/kW-yr) (36-3 mos)
(12 mos/yr)
= $2,337,500
Termination Payment B
Termination Payment B = Termination Payment A + One Time Payment
= $5,849,460 + $2,337,500
= $8,186,960
SAN DIEGO GAS & ELECTRIC COMPANY Revised Cal.P.U.C Sheet No.5083-E
San Diego, California Cancelling Original Cal.P.U.C. Sheet No.4242-E
Sheet 1
EXHIBIT F
RULE 21
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
A. General
1. This Rule presents the design and operating guidelines that should
be applied to Cogeneration and Small Power Production sources that
meet the criteria for a Qualifying Facility (QF) as defined by
Title 18, Code of Federal Regulation (CFR) Section 292.101(b)(1).
These guidelines are necessary to facilitate safe integration of
customer generation into the utility's system. In addition, the
QF must also comply with the utility's applicable rules
regulations.
2. These guidelines will cover 1) customer design requirements and
operating procedures and 2) utility design requirements and
operating procedures.
3. For the purpose of simplicity, the term customer will be used
in the guidelines to refer to both cogenerators and small power
producers.
B. Customer Systems Description
1. The customer may elect to use any of a variety of energy sources
including solar, wind or other alternative energy sources, in
addition to conventional fossil fuels. The end conversion for
connection to the utility's system must provide 60Hz alternating
current.
2. The customer may elect to run his generator in parallel with the
utility or as a separate system with capability of non-parallel
load transfer between the two independent systems. The
requirements for these two methods of operation are outlined
below.
C. Separate System (See Supplement I in Section K.)
1. A separate system is defined as one in which there is no
possibility of connecting the customer's generation in parallel
with the utility's system. For this design to be practical, the
customer must be capable of transferring load between the two
systems in an open transition or non-parallel mode. This can be
accomplished by either an electrically or mechanically interlocked
switching arrangement which precludes operation of both switches
in the closed position. The customer will be required to provide
protection to ensure adequate clearing of faults on his own
system.
Advice Ltr. No.603-E-SUPP. Issued by Date Filed April 13, 1984
Decision No.83-10-093 RONALD K. FULLER Effective May 13,1984
84-03-092 Vice President-Regulatory Services Resolution No.
Sheet 2 RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
C. Separate System (See Supplement I in Section K.) (Continued)
2. If the customer has a separate system, the utility will require
verification that the transfer scheme meets the non parallel
requirements. This will be accomplished by approval of drawings
by the utility in writing and, if the utility so elects, by field
inspection of the transfer scheme. The utility will not be
responsible for approving the customer's generation equipment and
assumes no responsibility for its designor operation.
3. Many Uniterruptible Power Supply (UPS) systems do not specifically
meet the separate system criteria. However, if they are not
capable of backfeed they will be classified as a separate system.
If they can backfeed, they must meet the requirements of parallel
operation.
D. Parallel Operation
A parallel system is defined as one in which the customer's generation
can be connected to a bus common with the utility's system. A transfer
of power between the two systems is a direct and generally desired
consequence. For this operation to be practical and safe, the
customer's equipment must meet the following conditions:
1. General Design Requirements
a. The customer's installation must meet all applicable
national, state, and local construction and safety codes.
b. All interconnection equipment at the customer's facility
shall be installed and maintained by the customer. If,
after review of the customer's design, it is determined that
in addition, equipment need be installed on the utility
through a power purchase or interconnection agreement with
the customer and in accordance with this Rule.
Sheet 3
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
D. Parallel Operation (Continued)
1. General Design Requirements (Continued)
c. A manual load break disconnect device shall be available
at or near the customer's main service point(s). This
disconnect device may be owned by either party but the
utility must have preemptory control for utility outages or
switching. The disconnect device must be capable of being
locked in the open position if the customer has access to
the disconnect device (see Section K.2.a.).
d. Voltage regulation equipment will be required on the
customer's generator to maintain service voltage within
normal utility limits (not required under 100 Kw).
e. Generator characteristics shall be specified and the
connection to the utility's system shall be designed to
limit voltage harmonic distortion to less than 3% for any
single frequency and to less than 5% total harmonic content.
If harmonic distortion causes interference to other utility
customers, the responsible party will redesign his system to
eliminate such interference.
f. The customer shall submit drawings and schematics of
interconnecting equipment and associated protection to the
utility for review and approval. Typical required drawings
will include, but not necessarily be limited to the
following prints: single line diagram, relay functional,
metering on line and switch gear details, circuit breaker
open and close control circuits. The utility will review
only those portions of the drawings and schematics which
apply to metering and the protection of the utility system.
The utility assumes no responsibility for review or approval
of equipment or circuit drawings pertaining to the
protection of the customer's system.
Sheet 4
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
D. Parallel Operation (Continued)
2. General Operating Requirements
a. The customer must maintain service voltage within normal
utility limits. If high or low voltage complaints or
flicker complaints result from operation of the customer's
generation, such generating equipment shall be disconnected
until the problem is resolved.
b. The customer shall discontinue parallel operation when
requested by the utility:
(1) To facilitate maintenance or repair of utility
facilities;
(2) During system emergencies;
(3) When the customer's equipment is operating in a
hazardous manner or is operating such that it is
interfering with other customers on the system.
NOTE: The utility may disconnect the customer from the
utility's system at any time without prior
notification, as system conditions may dictate.
c. The customer may not commence parallel operation of its
generator(s) until final written approval has been given by
the utility. The utility reserves the right to inspect the
customer's facility and witness testing of any equipment or
devices associated with the interconnection.
d. The utility reserves the right to inspect the customer's
facilities whenever it appears that the customer is
operating in an unsafe or harmful manner to the utility's
facilities, personnel or other customers.
Sheet 5 RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
D. Parallel Operation (Continued)
2. General Operating Requirements (Continued)
e. To assure the continued and safe operation of the
interconnection between the utility and the customer,
the utility recommends that the customer maintain and
calibrate his equipment and protective devices
associated with the interconnection to the utility on
a repetitive basis. The utility reserves the right to
require customers to provide the utility with
maintenance and calibration reports.
E. Customer Generation Less than 100 Kw (See Supplement II in Section
L.)
1. The utility shall provide and install metering, at a
location acceptable to the utility, as necessary to comply
with applicable customer generation gas and electric rate
schedules, power purchase contracts, or utility
requirements. The installation, operation, and maintenance
costs of these metering facilities shall be borne by the
customer, except as provided in Section J.l.d.
2. Where service is provided at or below 480 V, the customer is
to be served by a dedicated distribution transformer except
in the following circumstances:
a. The generator is under 10 kw, or
b. The generator is under lOO kw and is an induction
generator wherein the customer explicitly provides
for 24-hour immediate utility access to all
interconnection facilities as provided in Rule
l6.A.l.a.(1).
3. The customer should maintain his power factor within a
reasonable range. For small generators, power factor
correction may not be desirable.
4. The customer will be required to provide suitable devices to
ensure adequate protection for the following:
a. All faults on the customer's system.
b. All faults on the utility's system.
c. Backfeed or start-up of a customer's generator(s) into
a dead utility busSheet 6
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
E. Customer Generation Less Than 100 kw (See Supplement II in Section
L.) (Continued)
5. The following customer protective devices are required as a
minimum to effect connection and separation of the utility
and customer systems. For induction generators below 10 kw,
the following are recommended but not required. The
customer will still be responsible for providing
protection for the conditions of Section E.4.
a. Individual phase overcurrent trip devices.
b. Undervoltage trip devices.
c. Underfrequency trip devices.
d. Synchronizing or equivalent controls to ensure a
smooth connection with the utility's system.
6. The requirements listed in Section E.5. are based on the
utility's forecast that there will be a relatively small
amount of customer generation versus load for any particular
line on the utility's system. If a heavy saturation of
small power production on some line(s) does occur at a
future time, future customers may be required to provide
additional protection at that time. Where an induction
generator is to be installed, some of the trip devices may
be waived. Permission to waive certain devices will be
given only after a check of the supply circuit (for
capacitance) has been made and it has been determined that
the customer's generation will not be able to backfeed the
utility's system.
7. The customer shall not reconnect his generator after a
protective device trip unless his system is energized from
the utility source or unless he has isolated his system from
the utility.Sheet 7
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
F. Customer Generation Capacity 100 kw-1Mw (See Supplement III in
Section M.)
1. The utility shall provide and install metering, at a
location acceptable to the utility, as necessary to comply
with applicable customer generation gas and electric rate
schedules, power purchase contracts, or utility
requirements. The installation, operation, and maintenance
cost of these metering facilities shall be borne by the
customer.
2. The customer's generator(s) shall be designed and operated
to limit the adverse affects of reactive power flow on the
utility's system under all reasonably probable load
conditions. Generators shall be operated in a
manner to satisfy the reactive power requirement of the
customer's own load within the limits of the generator's
capability unless otherwise specified by the utility.
a. For synchronous generators, sufficient generator
reactive capability shall be provided to withstand
normal voltage changes on the utility's system.
b. For induction generators, capacitor installations will
likely be required for reactive power support. The
cost of such capacitors will be borne by the customer.
3. The customer shall install relaying to provide adequate
protection for the following:
a. All faults on the customer's system.
b. All faults on the utility's system.
c. Unbalanced or single phase conditions on the utility's
system.
d. Backfeed or start-up of the customer's generator(s)
into a dead utility bus.Sheet 8
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
F. Customer Generation Capacity 100 kw-1 (See Supplement III in
Section M.) (Continued)
4. Protective devices required are as follows:
a. Individual phase overcurrent trip devices.
b. Undervoltage trip devices.
c. Sensitive current unbalance relays.
d. Synchronizing controls; either automatic or manual.
e. Over/under frequency trip devices.
5. The customer shall not reconnect hi generator after a
protective device trip unless his system is energized from
the utility source, or unless he has isolated his system
from the utility. To prevent such hazardous connections,
the protective devices specified in Sections F.5.b. and
F.4.d. are required. In addition generator control
circuit(s) must be designed to prevent accidental generator
connection to a dead utility system. Design variations are
acceptable provided the requirements of Section F.3. are
satisfied.
G. Customer Generation Capacity Greater the 1 Mw (See Supplement IV
in Section N.)
1. The utility shall provide and install metering, at a
location acceptable to the utility, as necessary to comply
with applicable customer generation gas and electric rate
schedules, power purchase contracts, or utility
requirements. The installation, operation, and maintenance
costs of these metering facilities shall be borne by the
customer.
Sheet 9
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
G. Customer Generation Capacity Greater the 1 Mw (See Supplement IV
in Section N.) (Continued)
2. The customer's generator(s) shall be designed and operated
to limit the adverse affects of reactive power flow on the
utility's system under all reasonable probable load
conditions. Generators shall be operated in a
manner to satisfy the reactive power requirement of the
customer's own load within the limits of the generator's
capability unless otherwise specified by the utility.
a. For synchronous generators, sufficient generator
reactive capability shall be provided to withstand
normal voltage damages on the utility's system.
b. For induction generators, capacitor installations will
likely be required for reactive power support. Such
capacitors will be at the expense of the customer.
3. The customer shall install relaying to provide adequate
protection for the following:
a. All faults on the customer's system.
b. All faults on the utility's system.
c. Unbalanced or single phase conditions, or
deteriorating voltage waveform conditions on the
customer's generator(s).
d. Backfeed or start-up of the customer's generator(s)
into a dead utility bus.
4. Protective devices required are as follows:
a. Individual phase overcurrent trip devices.
b. Sensitive ground protection.
c. Over/under voltage trip devices.
Sheet 10
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
G. Customer Generation Capacity Greater than 1 Mw (See Supplement IV
in Section N.) (Continued)
4. (Continued)
d. Sensitive current unbalance relays.
e. Synchronizing controls; either automatic or manual
synchronizing supervised by a synchronizing relay.
f. Over/under frequency trip devices.
g. Telemetering or supervisory equipment (See Sections
G.6., G.7., G.8., and I.2.).
5. The customer shall not reconnect his generator after a
protective device trip unless his system is energized from
the utility source, or unless he has isolated his system
from the utility. To prevent such hazardous connections,
the protective devices specified in Sections G.4/c. and
G.4.e. are required. In addition, generator control
circuit(s) must be designed to prevent accidental generator
connection to a dead utility system. Design variations are
acceptable provided the requirements of Section G.3. are
satisfied.
6. Telemetering of Plant Output
Telemetering of the plant output (Mw, Mvar) to the Utility
Control Center, at customer's cost, is required when the
output of the customer's generation is greater than 2 Mw,
and the generation is operating in parallel with the
utility.
7. Utility Supervisory Control
When the customer is selling firm capacity greater than or
equal to 5 Mw to the utility, one of the following is
required:Sheet 11
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
G. Customer Generation Capacity Greater than 1 Mw (See Supplement IV
in Section N.) (Continued)
7. Utility Supervisory Control; (continued)
a. Complete supervisory control system allowing operation
of plant generation from the Utility Control Center.
b. Manning of generation facilities during all hours of
operation and all periods in which customer's facility
may be dispatched to allow operation as directed from
the Utility control Center.
8. Control and Indication of Customer's Main Breaker
When the total output of the customer's generation is less
than 5 Mw, control and indication of the customer's main
breaker will not generally be required. However, this
decision will be made on an individual basis by the utility.
H. Utility System Description
1. The vast majority of, if not all, customers with generation
will be connected to the utility's distribution system.
This is a radial system and past experience indicates these
loads are of a passive nature. The encouragement of
customers to install onsite generation, however, will
make backfeed a distinct possibility. The incorporation of
protective devices on the customer's equipment cannot be
relied upon to prevent all possibilities of backfeed. Since
backfeed is probable, the following design and operating
requirements must be incorporated.
2. Utility Design Requirements
a. A means of disconnection must be available on both
sides of the utility metering; must be under the
control of the utility; and shall be applied to all
customers with parallel generation.
Sheet 12
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
H. Utility System Description (Continued)
2. Utility Design Requirements (Continued)
a. (Continued)
This can be accomplished with switches, load break
elbows, cutouts or secondary breakers. Customer
disconnects can also be used provided that:
(1) The switches meet with utility approval.
(2) The utility has pre-emptive control.
b. Transformers feeding customers with parallel
generation shall be identified with a special tag
attached to the transformer or pole. This will notify
field crews of the possibility of backfeed. Incoming
load data sheets should be flagged and used to
initiate orders to tag poles.
c. All maps and diagrams used by System Operators to
direct switching operations shall have sources of
parallel generation identified.
d. A supervisory control and monitoring system will be
incorporated for those customers as specified in
Sections G.7. and G.8.
I. Utility Operation Procedures
1. As specified in Section H.1., backfeed from customer
generation is a distinct possibility. To maintain safe
working conditions, strict adherence to safety rules is
required. Utility procedure is to ground de-energized lines
and equipment upon which work will be performed.
2. The utility will exercise direct control over customer
generation to the extent allowed by the contract and
elsewhere in the Rule. A supervisory system is required for
this control (see Sections G.7 and G.8).
Sheet 13
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
I. Utility Operation Procedures (Continued)
3. The utility must have discretionary control over all
customer generation, independent of magnitude, during
outages, equipment maintenance or emergencies.
4. Additional safety control or procedures may be required as
experience dictates.
5. It is normal utility practice to utilize multi-shot high
speed reclosing on its distribution circuits.
J. Interconnection and Line Extension/Line upgrade Facility Cost*
1. General
a. The installation and maintenance costs of facilities
related to the interconnection of a customer's
facility (interconnection facilities) to the utility's
system, utilizing the utility's normal standards,
shall be borne by the customer.
b. The installation and maintenance costs of any line
extension line upgrade facilities, utilizing the
utility's normal standards, shall be borne by the
customer. Line extension/line upgrade facilities
are defined as all facilities exclusive of
interconnection facilities, determined by the utility
to be necessary to connect the utility's system to the
customer's point of delivery in order to accept the
output of the customer's generating facility. The
cost of any portion of the line extension/line upgrade
undertaken to serve future additional customers shall
be borne by the utility.
* As used in this Section J. only, the terms "interconnection
facilities" and "line extension/line upgrade facilities" refer
only to such facilities to be owned and maintained by the utility.
Sheet 14
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
J. Interconnection and Line Extension/Line Upgrade Facility Cost
(Cont'd.)
1. General (Continued)
c. The customer shall be responsible for the costs of
exploring the feasibility of a project or its
interconnection with the utility's system, including
reasonable advance charges imposed by the utility for
feasibility studies. A transmission line study for
any customer shall be completed by the utility within
the time period identified by the utility in
accordance with the applicable procedures as
established by the California Public Utilities
Commission.
d. The customer shall be responsible for costs of
metering, telemetering (to the extent required under
this Rule), and safety checks except to the extent
that, under the utility's existing other rules, a
comparable customer would not be similarly charged.
Where the customer's generating facility is less that
20 kw, except those customers remaining on Schedule AD
after June 30, 1987, and customer does not require
that power delivered to the utility be measured on a
time-of-delivery basis, the utility will bear the cost
of installing, operating and maintaining one standard
watt-hour meter (and current transformers if required)
to measure power flows from the customer to the
utility. The customer shall provide and install
necessary meter sockets and enclosure equipment at or
near the point of delivery.
e. The customer shall be responsible for the installation
and maintenance costs of only those future utility
system alterations which are necessary to maintain the
California Public Utilities Commission's adopted
interconnection standards for the customer's
particular interconnection facilities. Said standards
shall be those in effect at the time customers and
utility sign the power purchase or interconnection
agreement. Should a line extension/line upgrade not
be directly required by or beneficial to the customer,
the customer shall be treated like any other customer
on the utility's system.
Sheet 15
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
J. Interconnection and Line Extension/Line Upgrade Facility Cost (Cont'd)
1. General (Continued)
f. When the customer wishes to continue to reserve
interconnection and line extension/line upgrade facilities
which were previously paid for by the customer, but have
been idled by an energy sale conversion, the utility shall
continue to charge the customer an operation and maintenance
(O&M) charge for these facilities. When the customer no
longer needs the facilities for which he has paid, or fails
to pay the required O&M charge, a termination payment due to
the utility or customer shall be calculated in accordance
with the applicable sections of the Rule and the power
purchase or interconnection agreement.
g. The utility shall treat any money collected from a customer
for a line extension/line upgrade that accommodates a second
customer in the same manner as customer advances would be
treated under the utility's regular line extension rules for
other customers.
h. The O&M charge required under this Section J. shall commence
at such time as the facilities are installed and able to be
used.
2. Allocation of the utility's Existing Line Capacity
For purposes of interconnecting the customer with the utility,
existing capacity on the utility's transmission and/or
distribution system and a priority to such line capacity will be
allocated as follows:
a. For a customer who receives either a final Standard Offer
#4, a Standard Offer #2, or a Uniform Standard Offer #1, the
following shall apply;
(1) For a customer who bids for and receives a final
Standard Offer #4 Power Purchase Agreement, entitlement to
existing capacity on the utility's transmission and/or
distribution system and a priority to such line capacity
will be established as of the date its bid is accepted by
the utility; or
Sheet 16
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
J. Interconnection and Line Extension/Line Upgrade Facility Cost (Cont'd)
2. Allocation of the Utility's Existing Line Capacity (Continued)
a. (Continued)
(2) for a customer who submits an application for and
receives a Standard Offer #2, entitlement to existing
capacity on the utility's transmission and/or distribution
system and a priority to such line capacity will be
established as of the date the customer pays for and
provides all information necessary for the utility to
conduct either a preliminary or detailed interconnection
study; or for an out-of-service area Seller, as of the date
Seller pays the costs and provides all information necessary
for the utility to conduct a Line Loss and transmission
Impact Study as defined in the Standard Offer #2 Agreement;
or
(3) for a customer who signs a Uniform Standard Offer #1
Agreement, entitlement to existing capacity on the utility's
transmission and/or distribution system and a priority to
such line capacity, will be establish as of the date the
customer both pays the Project Fee and pays the cost of, and
provides all information necessary for the utility to
conduct, either a preliminary or detailed interconnection
study, as defined in the Uniform Standard Offer #1
Agreement.
b. For a customer who signs a non-standard power purchase
agreement, entitlement to existing capacity on the utility's
transmission and/or distribution system and a priority for
such capacity will be established per the terms and
conditions specified in such non-standard agreement,
consistent with the above or as otherwise provided in such
non-standard contract.
c. If a customer fails to perform any of the obligations
specified in the Commission's authorized bidding protocol or
queue management procedures, whichever is applicable, or
fails to meet one of the performance milestones specified in
the power purchase agreement executed by the parties, the
customer's allocation of existing capacity and priority to
said line capacity shall be terminated and shall be
reallocated to other uses.
Sheet 17
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
J. Interconnection and Line Extension/Line Upgrade Facility Cost (Cont'd).
Allocation of the Utility's Existing Line Capacity (Continued)
d. In the event that the customer losese his priority for available
line capacity but desires to continue the project, the terms of
the power purchase agreement and applicable law, shall determine
whether the power purchase agreement is subject to termination as
a result of such loss of priority, and the manner in which new
priority may be established.
e. Where existing line capacity is allocated to a customer, the
customer shall incur no obligation for costs associated with
future line upgrades needed to accommodate other customers. If
existing line capacity is not sufficient to facilitate the
customer's capacity requirements, the customer shall bear the cost
of any additional line upgrade necessary to facilitate the
customer's capacity requirement. If two or more customers
establish priority rights simultaneously, the customers shall
share the costs of any additional line upgrade necessary to
facilitate their cumulative capacity requirements. Costs shall be
shared based on the relative proportion of capacity each customer
will add to the line.
3. Customer Installation of the Interconnection and Line
Extension/Line Upgrade Facilities (Exclusive of Metering)
At the option of the customer, installation of that portion of the
customer's interconnection and line extension/line upgrade
facilities (exclusive of metering) that is not covered by the
utility's regular line extension rules may be performed by the
customer's contractor under the guidelines of and subject to the
conditions and exceptions contained in Rule 15, Section E.8 and
the following:
Sheet 18
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
J. Interconnection and Line Extension/Line Upgrade Facility Cost (Cont'd)
3. Customer Installation of the Interconnection and Line
Extension/Line Upgrade Facilities (Exclusive of Metering)
(Continued)
a. The customer signs a power purchase or interconnection
agreement with the utility specifying the facilities to be
installed by the customer;
b. Prior to construction, the customer makes payment to the
utility, for the utility installation. The payment shall
include a CIAC tax gross-up and shall be made to the utility
pursuant to the utility's extension rules; and
c. The customer makes payment to the utility of a monthly
operation and maintenance charge which shall be determined
as 0.7% of the sum of the actual installed cost of the
facilities deeded to the utility plus the estimated or
actual installation cost (as selected in accordance with
Section J.4.b.) of the metering provided by the utility.
In the event that the customer terminates the use of the
iter-connection and line extension.line upgrade facilities at an
time, the customer will make a termination payment to the utility
which shall be determines as follows:
(1) The estimated or actual* installation cost of the metering
provided by the utility plus the estimated removal cost of the
interconnection and line extension/line upgrade facilities, less
(2) The salvage value of any materials removed and the fair
market value of any facilities the utility will continue to use to
service other customers rather than removing, less
(3) The estimated or actual* installation cost of the metering
that was previously paid in advance to the utility by the
customer.
If the termination payment as determined above is negative, then
the utility will refund that amount, without interest, to the
customer.
- - ---------------------------------
*If the actual cost option was selected in Section J.4.b.
Sheet 19
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
J. Interconnection and Line Extension/Line Upgrade Facility Cost (Cont'd)
Utility Installation of the Interconnection and Line Extension/Line
Upgrade Facilities
At the option of the customer, installation of the interconnection and
line extension/line upgrade facilities may be made by the utility,
provided the type of facilities requested are acceptable to the utility
and the utility agrees to the installation of the facilities under the
following conditions:
a. The customer will execute a power purchase or interconnection
agreement covering the installation of the interconnection and
line extension/line upgrade facilities.
b. Prior to commencement of the installation of the facilities and as
part of the power purchase or interconnection agreement, the
customer will choose to pay the cost of installation based on
either actual cost or a binding estimate.
c. Payment Method for Interconnection Facility
The customer will choose one of the following options to provide
payment to the utility for the installation and maintenance costs
of the interconnection facility:
(1) Option 1
(a) The customer will advance to the utility, prior to
construction, the estimated installed cost of the
interconnection facilities and related engineering fees.
(b) If the customer chooses to pay for installation based
on actual cost (as specified in Section J.4.b.), the utility
will, as soon as practical after the interconnection
facilities are completely installed by the utility, wither
bill or refund to the customer, as applicable, any
difference between the estimated and actual installed cost
of the interconnection facilities.
Sheet 20
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
J. Interconnection and Line Extension/Line Upgrade Facility Cost (Cont'd)
4. Utility Installation of the Interconnection and Line
Extension/Line Upgrade Facilities (Continued)
c. Payment Method for Interconnection Facility (Continued)
(1) Option 1 (Continued)
(c) The customer will make payment to the utility of
a monthly operation and maintenance (O&M) charge
which shall be determined as 0.7% of the
estimated or actual installed cost (as selected
in accordance with Section J.4.b.) of the
interconnection facilities.
(d) In the event that the customer terminates the
use of the interconnection facilities at any
time, the customer will make a termination
payment to the utility which shall be determined
as follows:
(i) The estimated or actual* installation cost
plus the estimated removal cost of the
interconnection facilities, less
(ii) The salvage value of any materials removed
and the fair market value of any facilities the
utility will continue to use to service other
customers rather than removing, less
(iii) The estimated or actual* installation
cost of the interconnection facilities that was
previously paid in advance to the utility by the
customer.
*If the actual cost option was selected in Section J.4.b.
Sheet 21
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
J. Interconnection and Line Extension/Line Upgrade Facility Cost (Cont'd)
4. Utility Installation of the Interconnection and Line
Extension/Line Upgrade Facilities (Continued)
c. Payment Method for Interconnection Facility (Continued)
(1) Option 1 (Continued)
(d) (Continued)
If the termination payment as determined above
is negative, then the utility will refund that
amount without interest, to the customer.
(2) Option 2
(a) The customer will make payment to the utility of
a monthly interconnection facility (IF) charge
for a term of 60 months commencing when the
utility begins work to install the removable and
reusable interconnection facilities. The
monthly charge will be 3.4% of the estimated
installed cost of the removable and reusable
interconnection facilities. Removable and
reusable interconnection facilities may include
such items as transformers. disconnect switches,
circuit breakers, protective relays, and other
related equipment which can be removed and
reused by the utility in the event that the
customer terminates the use of the
interconnection facilities. The utility
reserves the right to determine individually the
removable and reusable interconnection
facilities, This determination will be subject
to confirmation by the utility at such time the
customer terminates either his power purchase or
interconnection agreement or his use of the
interconnection facilities, whichever is
earliest.
Sheet 22
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
J. Interconnection and Line Extension/Line Upgrade Facility Cost (Cont'd)
4. Utility Installation of the Interconnection and Line
Extension/Line Upgrade Facilities (Continued)
c. Payment Method for Interconnection Facility (Continued)
(2) Option 2 (Continued)
(b) The customer will advance to the utility, prior
to construction, the related engineering fees
for the total installation and the estimated
installed cost of those interconnection
facilities that cannot be removed and reused by
the utility.
(c) If the customer chooses to pay for installation
based on actual cost (as specified in Section
J.4.b.), the utility will, as soon as practical
after the interconnection facilities are
completely installed by the utility, calculate a
revised monthly IF charge based on the actual
installed cost of the removable and reusable
interconnection facilities. The utility will
either bill or refund to the customer, as
applicable, to account for the difference in IF
charge based on the estimated versus the actual
installed cost of such facilities. Once the
revised monthly IF charge is determined, future
monthly payments by the customer to the utility
will be at the revised monthly charge.
(d) The customer will make payment to the utility of
a monthly operation and maintenance (O&M) charge
which shall be determined as 0.7% of the total
estimated or actual installed cost (as selected
in accordance with Section J.4.b.) of the
interconnection facilities.
Sheet 23
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
J. Interconnection and Line Extension/Line Upgrade Facility Cost (Cont'd)
4. Utility Installation of the Interconnection and Line
Extension/Line Upgrade Facilities (Continued)
c. Payment Method for Interconnection Facility (Continued)
(2) Option 2 (Continued)
(e) In the event that the customer terminates the
use of the interconnection facilities, the
customer will make a termination payment to the
utility which shall be determined as follows:
(i) The total estimated or actual* installed
cost plus the estimated removal cost of the
interconnection facilities, less
(ii) The salvage value of any materials removed
and the fair market value of any facilities the
utility will continue to use to service other
customers rather than removing, less
(iii) The estimated or actual* installed cost
of the interconnection facilities that cannot be
removed and reused by the utility that was
previously paid in advance to the utility by the
customer, less
(iv) The capital contribution of the monthly IF
charge as calculated by the utility.
If the termination payment as determined above
is negative, then the utility will refund that
amount, without interest, to the customer.
*If the actual cost was selected in Section J.4.b.
Sheet 24
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
J. Interconnection and Line Extension/Line Upgrade Facility Cost (Cont'd)
4. Utility Installation of the Interconnection and Line
Extension/Line Upgrade Facilities (Continued)
c. Payment Method for Interconnection Facility (Continued)
(2) Option 2 (Continued)
(f) Prior to the utility's acceptance of this
option, the customer shall provide and maintain
one of the following:
(i) A letter of Credit which will guarantee
payment of the estimated installed cost of the
interconnection facilities that is in excess of
the advance payment made by the customer under
Section J.4.c.(2)(b),
(ii) A Surety Bond, acceptable to the utility,
which will guarantee payment of the estimated
installed cost of the interconnection facilities
that is in excess of the advance payment made by
the customer under Section J.4.c.(2)(b),
(iii) A similar security, acceptable to the
utility, which will guarantee payment of the
estimated installed cost of the interconnection
facilities that is in excess of the advance
payment made by the customer under Section
J.4.c.(2)(b).
d. Payment Method for Line Extension/Line Upgrade Facilities
(1) The customer will advance to the utility, prior to
construction, the estimated installed cost of the line
extension/line upgrade facilities and related
Sheet 25
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
J. Interconnection and Line Extension/Line Upgrade Facility Cost (Cont'd)
4. Utility Installation of the Interconnection and Line
Extension/Line Upgrade Facilities (Continued)
d. Payment Method for Line Extension/Line Upgrade Facilities
(Continued)
(1) (Continued)
engineering fees. The customer will make payment to
the utility of a monthly operation and maintenance
(O&M) charge which shall be determined as 0.7% of the
estimated or actual installed cost (as selected in
accordance with Section J.4.b) of the line
extension/line upgrade facilities.
(2) If the customer chooses to pay for installation based
on actual cost (as specified in Section J.4.b.), the
utility will, as soon as practical after the line
extension/line upgrade facilities are completely
installed by the utility, either bill or refund to the
customer, as applicable, any difference between the
estimated and actual installed cost of the line
extension/line upgrade facilities.
(3) In the event that the customer terminates the use of
the interconnection and line extension/line upgrade
facilities, the customer will make a termination
payment to the utility for the line extension/line
upgrade facilities which shall be determined as
follows:
(i) The estimated or actual* installation cost plus
the estimated removal cost of the line extension/line
upgrade facilities, less
Sheet 26
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
J. Interconnection and Line Extension/Line Upgrade Facility Cost (Cont'd)
4. Utility Installation of the Interconnection and Line
Extension/Line Upgrade Facilities (Continued)
d. Payment Method for Line Extension/Line Upgrade Facilities
(Continued)
(3) (Continued)
(ii) The salvage value of any materials removed and
the fair market value of any facilities the utility
will continue to use to service other customers rather
than removing, less
(iii) The estimated or actual* installation cost of
the line extension/line upgrade facilities that was
previously paid in advance to the utility by the
customer.
If the advance payment for the line extension/line
upgrade was shared among more than one customer, the
termination payment for each customer will be
determined in the same proportion as each customer's
advance payment bears to the total advance payment.
If the termination payment as determined above is
negative, then the utility will refund that amount,
without interest, to the customer.
*If the actual cost option was selected in J.4.b.
Sheet 27
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
K. Supplement I - Typical Separate System Installation.
SUPPLEMENT I - SEPARATE SYSTEM
(Diagram)
NOTES: 1. Switches Interlocked so both
cannot be closed at same time.
2. Additional phase and ground
protection may be required
where service is taken at 12
kv or higher.
Relay Identification
M = Meter 3. Complete electrical metering
requirements are not
indicated. A separate
metering guidelines
publication is available from
the utility.
Sheet 28
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
L. Supplement II - Typical Installation of Under 100 kw.
(Diagram)
Sheet 29
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
M. Supplement III - Typical Installation of Under 100 kw to 1 MW.
(Diagram)
Sheet 30
RULE 21 (Continued)
CUSTOMER-OWNED GENERATION--QUALIFIED FACILITIES
N. Supplement IV - Typical Installation of 1 MW and Above.
(Diagram)
EXHIBIT 10.43
Amendment One
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .QFE 200.416(a)
This amends the Standard Offer No. 2 Agreement between
Bonneville Pacific Corporation (Seller) and San Diego Gas and
Electric Company (SDG&E).
Seller and SDG&E have different interpretations of the date by
which Seller must provide evidence of firm transmission to SDG&E.
This amendment reflects the resolution of these differences.
1. The effective date is June 15, 1990.
2. Substitute "effective date" for "date of execution" in the
second line of section 5.5.1. and in section 2.4.2.
3. Section 4.2.2 (d) is deleted.
The Agreement is hereby reconfirmed in all other respects.
/s/ James F. Kenney Date
James F. Kenney
Director - Resource Development and Contracts
San Diego Gas and Electric Company
/s/ Robert A. Keegan Date
Robert A. Keegan
Vice President - Development
Bonneville Pacific Corp.
JOINT VENTURE AGREEMENT
California Energy Company, Inc. ("CE") and Kiewit Diversified Group
Inc. and Kiewit Construction Group Inc. (collectively one Party hereunder
and referred to as "Kiewit") each recognize the unique strengths of the
other Party and hereby form a Joint Venture to develop, construct, own and
operate power projects internationally as follows:
Strengths: CE brings power project development expertise,
power project financing expertise, financial
wherewithal, power project operational expertise,
broad knowledge of the international power markets
and knowledge of the specific international power
project opportunities available.
Kiewit brings extensive power project construction
expertise, EPC turnkey contract capability, bonding
and performance and completion guarantee
capability, vendor relationships, infrastructure
development expertise, financial wherewithal, coal
mining expertise, and a broad knowledge of the
power markets internationally.
Power Projects: Each Party has the right of first refusal to pursue
through this Joint Venture, all build, own and
operate or build, own, operate and transfer power
projects identified by the other Party or its
affiliates outside of the United States except
those in which (i) the Joint Venture could not
acquire a controlling interest in the equity, (ii)
bid constraints would effectively prevent Kiewit's
or CE's participation, (iii) participant,
contractor or partner constraints would
effectively prevent Kiewit's or CE's participation,
or (iv) the power project location is in the
Caribbean, South America or that part of Central
America south of Mexico and such project is subject
to the right of Distral, S.A. to be developed with
CE under a CE/Distral Joint Venture Agreement
("Distral Projects"); provided that, with respect
to Distral Projects, CE shall offer Kiewit the
opportunity to bid on civil construction or coal
supply or (if CE has the right to acquire more than
50% of the equity in such Distral Projects), to
participate with CE in the development funding and
equity, on a 50/50 basis, in each case pursuant to
the terms of CE's Joint Venture Agreement with
Distral, S.A.
Each Party shall notify the other Party of any
power project subject to the right of refusal as
soon as such Party believes that such project may
be subject to the right of refusal. If the Joint
Venture does not promptly elect to pursue the
identified power project, either Party may pursue
the power project separately.
Development Manager
& Development Costs: The Parties shall share all project development
costs equally. Development costs shall only be
incurred by, or at the direction of, CE as the
Joint Venture Development Manager and shall include
all development costs incurred after a power
project has been identified and offered to the
Joint Venture until a Party declines to participate
in such project or a Party or the Joint Venture or
a Project Entity abandons or transfers its interest
in a project or a Party is otherwise required to
discontinue its participation in a project.
Development costs include out-of-pocket, third
party expenses incurred by the Parties in
furtherance of development of a power project as
well as the actual cost associated with employees
of the Parties who perform work to develop a power
project, in each case at the direction of the
Development Manager.
In no event shall the reimbursable costs for
employees be credited in excess of the actual
fully burdened cost (as mutually agreed by the
Parties) for the actual time period involved by
such staff in Joint Venture development activities.
It is anticipated that CE employees will perform a
majority of the development activities. Kiewit
shall have the ability, however, to dedicate up to
one full-time equivalent employee to Joint Venture
activities, subject to agreement by the Parties as
to appropriate time commitment and cost
reimbursement arrangements with respect thereto.
Each Party shall submit bills (and provide all
reasonably requested supporting documentation) for
such development costs on a monthly basis and each
Party's share of such costs shall be payable within
30 days of submission of such bills .
Semiannually, the Parties shall review and
reconcile any development costs incurred hereunder.
Verified development costs shall be recovered at
project financial closing unless converted to
equity or subordinated debt in the projects.
Management
Committee: The Parties shall establish a management committee
to be comprised of two representatives of each of
CE and Kiewit, who shall act as agents of the
parties appointing them, to oversee and direct
Joint Venture management level decisions.
Management committee decisions shall be made by
majority vote. In the event of a deadlock
regarding a particular project under development
which cannot be resolved by the good faith
negotiations of the Parties, (including the failure
to reach agreement on a turnkey construction
contract) either Party shall have the right by 15
days prior written notice to trigger a mandatory
discontinuance of both Parties with respect to the
particular project, in which case the
discontinuance provision below shall apply and CE
shall have the exclusive right to pursue such
project independently; provided however, that the
Parties shall negotiate mutually acceptable
deadlock resolution and buyout provisions, which
may vary from the foregoing provision as part of
the organizational documents for each Project
Entity. Each management committee shall have
meetings not less often than quarterly. The
Development Manager shall prepare, and the
management committee shall approve, and review as
necessary, annual budgets for Joint Venture
activities. Day to day operational decisions
relating to the Joint Venture, as well as
individual projects and Project Entities shall be
made by the Development Manager.
Turnkey Construction: Where the ability to select the turnkey contractor
is within the Joint Venture's control, CE on
behalf of the Joint Venture shall provide a
preferential opportunity to Kiewit or an affiliate
thereof to negotiate a turnkey construction
contract with CE acting on behalf of the Joint
Venture for each such project. Kiewit shall
provide completion and performance guarantees and
appropriate security (e.g. letter of credit,
guarantee, bond) reasonably required by project
finance lenders or other third party project
participants to secure performance of its
contractual obligations. Prior to entering into
the turnkey contract, CE and Kiewit shall jointly
(i) agree upon the technical/ systems/vendors to
be utilized, taking into account market conditions
and project financing requirements and (ii) price
and select items of equipment whose value exceeds
$250,000. CE and Kiewit shall jointly select the
engineering firm to be used by Kiewit for the
turnkey pricing and contract; provided that, to the
extent capable, The Ben Holt Co. will be given a
preferential opportunity to negotiate such an
engineering role in the turnkey contract for each
such project.
Project Entity: After a power project has reached an appropriate
stage of development, CE shall endeavor to create a
Project Entity (e.g., corporation, limited
liability company, partnership), which shall be
reasonably acceptable to both Parties, to undertake
the financing of such power project. The Project
Entity organizational documents shall reflect the
equity participation of the Parties and the fact
that CE shall act as the managing general partner
or in an analogous operating or managing role for
such Project Entity, subject to mutually acceptable
management or shareholder approval rights in favor
of Kiewit. The provisions set forth in this Joint
Venture Agreement relating to the terms and
conditions of each Project Entity may be varied by
mutual agreement of the Parties; in the event of
any conflict between this Agreement and any
agreement relating to a Project Entity, the
agreement relating to the Project Entity shall
control.
Capital Contributions: Unless otherwise negotiated by the Parties, CE and
Kiewit shall each provide 50% of the equity or
other sponsor-provided funding required from the
Parties for financing a power project developed by
the Joint Venture or a Project Entity. If agreed
by the Parties and acceptable to project lenders,
equity contributions may be made in the form of
construction or engineering or other services
performed. Development costs may be considered
equity contributions of the Parties to the extent
agreed by the Parties and permitted by the
applicable project lender. The Parties acknowledge
that any commitment by either Party to invest
equity will be conditioned upon obtaining
acceptable rates of return and other acceptable
provisions.
Profit/Loss/
Distributions: All profits, losses and other distributions
(including fees and other similar compensation)
arising from Joint Venture or Project Entity
activities after repayment of development costs
(other than profits and losses arising under
separate construction and operation and maintenance
contracts) shall be allocated 50/50 to CE and
Kiewit or otherwise in accordance with each Party's
equity contribution.
Operations &
Maintenance: CE shall serve as operator of all power projects
developed by the Joint Venture or a Project Entity under
an agreement acceptable to the Parties and project
lenders which provides reasonable oversight to the
Parties over operational expenses and activities. CE
shall provide appropriate security (e.g. letter of
credit, guarantee, bond) reasonably required by lenders
or other third parties to secure performance of its
contractual obligations as operator.
Accounting: As Development Manager, CE shall maintain, on behalf of
the Joint Venture, records of development costs and such
other matters as are reasonably required in connection
with Joint Venture activities. The records of the
Development Manager and each Project Entity shall be
accurate in all material respects and shall fairly
present the position and results of the Joint Venture and
each Project Entity and shall be prepared on an accrual
basis in accordance with U.S.A. generally accepted
accounting principles consistently applied.
Discontinuance: Except for binding obligations under executed contracts
including construction or operation and maintenance
agreements, with respect to any project, either Party
may elect to discontinue its participation in the Joint
Venture or any project or Project Entity by delivering
written notice to the other 15 days in advance of its
discontinuance provided that the discontinuing party
shall use all reasonable efforts to ensure that such
discontinuance shall not be made in a manner which would
disrupt any near term pending proposals and/or
negotiations such that the remaining Party is injured and
cannot continue with the proposal/negotiations. Upon
delivery of such notice, the Parties shall for no
additional consideration, execute appropriate assignment,
assumption, indemnity and release documents which
transfer, as of the date of the date of discontinuance,
to the remaining Party (or an affiliate thereof as
designated by such remaining Party) all obligations and
rights in the respective project or Project Entity or in
all power projects identified to the Joint Venture, but
not yet transferred to a Project Entity, whichever is
applicable. Such discontinuance by a Party shall be
immediately effective as an assignment of its interest in
any power project; however, the discontinuing Party shall
pay its share of development costs incurred by the Joint
Venture or Project Entity on or before the date of
discontinuance, although such expenses may come due
later. The discontinuing Party shall be entitled to be
repaid its share of the development costs with respect to
any discontinued project out of the construction or
project financing therefor, but only after repayment to
the remaining party (and any new equity participants) of
all development costs incurred with respect to the
Project.
Right of First Refusal:
Notwithstanding any provision of this Agreement to the
contrary, either Party ("Selling Party") may sell or
transfer its interest in , any project or Project Entity
(but not the Joint Venture) to a third party, provided it
first notifies the other Party ("Offeree Party") of the
identity of the prospective purchaser, assignee or
transferee and sends to the Offeree Party a copy of the
written offer, and provided further that the Selling
Party shall first offer to sell all its interest in , any
project or Project Entity to the Offeree Party for the
same price, and on the same terms as those being offered
to the Selling Party. The Offeree Party shall have 90
days after receiving such offer to accept it. If the
Offeree Party does not agree to purchase the Selling
Party's interest in , any project or Project Entity with
the 90 day period set forth above, the Selling Party may
sell its interest in , any project or Project Entity on
the terms first proposed in the written offer sent to the
Offeree Party; provided, however, that no Party may
transfer its interest in , any project or Project Entity
to another unless the transferee agrees in writing to be
bound by the same terms and conditions of this Agreement
(as it applies to such project or Project Entity) and
becomes a party hereto.
Compliance with Law:
In performing their respective activities hereunder, each
Party agrees to comply with all applicable United States,
and other applicable laws. In this regard, each Party
agrees that neither it nor its employees, agents or
subcontractors shall make any payment or give anything of
value to any government official to influence a
government decision, or to gain any other governmental
advantage for the Parties, the Joint Venture, any project
or a Project Entity in connection with the activities
performed hereunder.
Assignment: Except for assignments to affiliates and assignments to
lenders and others (which each Party agrees to make as
reasonably required for project financing) and
assignments pursuant to the Right of First Refusal set
forth above, neither Party may sell, transfer, assign or
otherwise encumber any portion of its interest in the
Joint Venture any project, or any Project Entity without
the other Party's prior written consent. For purposes of
this Agreement "Affiliate" of a Party shall mean a person
or entity controlling, controlled by or under common
control with the Party.
Nature of Joint Venture:
The Joint Venture shall not be considered, and this
Agreement shall not be considered to have formed, a
partnership or other legal entity. Except for CE's
rights to incur project development expenses and act on
behalf of the Joint Venture as Development Manager within
the scope of this agreement, unless otherwise agreed,
neither Party shall be the agent or representative of, or
have the power to legally bind, the other Party in
connection with the activities of the Joint Venture, and
each Party shall be severally liable for any obligations
to third parties incurred in connection with Joint
Venture activities.
Term: The initial term of the Joint Venture shall be 3 years;
but the term may be extended by mutual agreement of the
Parties. The Joint Venture shall extend automatically
successive terms of one year at the end of its term but
only for the sole purpose of considering identified power
projects not yet rejected or pursuing power projects for
which a Project Entity has not yet been formed. The term
of each Project Entity shall be as set forth in its
organizational documents which shall establish a term at
least as long as is required to complete the development,
construction and operation of its respective power
project. The term of the Right of First Refusal for any
identified project or Project Entity shall extend for a
term equal to the applicable Party's right to an equity
participation in such project or Project Entity.
Notwithstanding the foregoing, the term of this Joint
Venture shall terminate upon the bankruptcy or
dissolution of either Party.
Cooperation: Since this Joint Venture Agreement is expected to
continue for some time and both Parties recognize that
international power projects can present unique
challenges or require special arrangements, both Parties
will attempt in good faith to negotiate additional terms
or modifications to this Agreement in response to any
such unique circumstances which are encountered,
consistent with the intent of the Parties in forming this
Joint Venture.
This Joint Venture Agreement has been duly authorized and executed by
each Party and is intended to be a legally binding and enforceable
agreement under, and governed by, the laws of the state of New York,
U.S.A.
Dated as of: December 14, 1993
Kiewit Diversified Group Inc. California Energy Company, Inc.
By:/s/ Walter Scott, Jr., President By: /s/ David L. Sokol
Walter Scott, Jr., President David L. Sokol,
Chairman of the Board President and Chief
Executive Officer
Kiewit Construction Group Inc.
By:/s/ Kenneth E. Stinson
Kenneth E. Stinson, President
and Chairman of the Board
EXHIBIT 10.45
Joint Venture Agreement
California Energy Company, Inc. ("CE") and Distral S.A.
("Distral") each recognize the unique strengths of the other
company and in consideration of the mutual covenants and
agreements herein contained and for other good and valuable
consideration, the parties hereby form a Joint Venture to
develop, construct, own and operate power projects (including
all development, acquisition, repowering and privatization
opportunities) in Central America, South America and the
Caribbean as follows:
Strengths: CE brings power project development
expertise, power project financing
expertise, financial wherewithal, vendor
relationships, power project operational
expertise, broad knowledge of the
international power markets and, through
its relationship with Peter Kiewit
Sons', Inc. ("Kiewit"), civil
construction and coal mining expertise.
Distral brings extensive construction
experience throughout Central and South
America, financial capability, vendor and
utility relationships, substantial knowledge
of the customs and commercial practices
throughout Central and South America, and a
broad knowledge of the power markets in
Central and South America as well as
knowledge of the specific power project
opportunities available in that region.
Power Projects: The Joint Venture shall have the right
of first refusal with respect to all
power projects identified by the Joint
Venture, CE, Distral or their affiliates
(including all members of the Lancaster
Distral Group of companies but excluding
Kiewit) in the Caribbean, South America
and that part of Central America south
of Mexico. CE, Distral and their
affiliates shall promptly notify the
Joint Venture and the other Party of any
power projects in such countries after
such power project becomes known by it.
If the Joint Venture's management
committee does not elect to pursue the
identified power projects, either Party
may pursue the power project separately.
Development Costs: The Parties shall share all project
development costs equally. Development
costs shall include all costs and fees
(but unless otherwise agreed, not equity
contributions provided for below)
incurred by the Parties pursuant to
management committee approval after a
power project has been identified and
offered to the Joint Venture until the
Joint Venture or Project Company
abandons or transfers the Project.
Expenditures include out-of-pocket,
third party expenses incurred by a Party
and their affiliates in furtherance of
development of a power project as well
as expenditures for the cost associated
with employees of a Party who are
assigned to a power project, which costs
must be approved by the management
committee. In no event shall
expenditures for employees be credited
to a Party in excess of $50 per hour for
more than 40 hours during any week. The
Parties shall reconcile development
costs quarterly to balance the cost
sharing borne by each Party. Verified
development costs shall be recovered at
project financial closing unless
converted to equity, subordinated debt
or other income streams.
Project Company: After a power project has reached an
appropriate stage of development as
determined by the management committee,
the Parties shall endeavor to create a
Project Company (e.g., corporation,
limited liability company, partnership)
to undertake the development of the
power project.
EPC: Distral shall have the right of first
refusal to negotiate a mutually
acceptable contract to supply equipment,
boilers and transportation, field
erection, project construction
management and engineering services for
all or any part of a power project (to
the extent appropriate and consistent
with the paragraph below on Civil
Construction) developed by the Joint
Venture or a Project Company. Distral
shall provide appropriate security (e.g.
guarantee, bond) required by lenders or
other third parties to secure
performance of such contractual
obligations.
Performance Guarantees
and Bid Bonds: If so required by each project's
lenders, CE shall use its reasonable
efforts to arrange any "wrap-around"
credit support undertakings or
completion and performance guarantees
from Kiewit or other third parties.
Distral shall be responsible to CE for
Distral's scope of equipment supply, EPC
participation and related performance.
Both Parties recognize that bid bonds or
other financial security or O&M
guarantees may be required to pursue
projects and that it will be necessary
for both Parties to make suitable and
mutually acceptable bonding and other
such arrangements for projects they
determine to pursue.
Fuel, Technology Systems
& Vendor Selection(s): At the outset of each project, the
Joint Venture shall perform
preliminary feasibility studies to
determine the optimum
technical/systems to be utilized
taking into account market
conditions and project financing
requirements. Vendor equipment
shall be competitively bid unless
the management committee decides to
negotiate otherwise.
Operations and
Maintenance: CE and Distral shall have a first right
of refusal to negotiate a mutually
acceptable contract to jointly operate
and maintain each project on a long term
basis. In connection with the joint
operation and maintenance, CE shall
provide overall supervision, management
and related support systems including
accounting expertise and Distral shall
provide local qualified labor and
undertake all maintenance and overhaul
services not directly supplied by any
contracted vendor.
Coal Supply: Where reasonably practicable the Joint
Venture shall initially negotiate with
Kiewit or an affiliate thereof with
respect to the opportunity to
participate in coal supply for a coal-
fired power project on terms acceptable
to both Parties.
Civil Construction: Where reasonably practicable the
Joint Venture shall initially
negotiate with Kiewit or an
affiliate thereof with respect to
the opportunity to participate in
civil engineering and construction
of any power project on terms
acceptable to both Parties.
Capital Contributions: CE shall provide a minimum capital
contribution of at least 50% of the
equity required for financing a
power project developed by the
Joint Venture or a Project Company.
Distral shall provide a capital
contribution of up to 50% of the
equity required for financing a
power project developed by the
Joint Venture or Project Company.
Distral may elect to provide less
than 50% of such required equity in
which event, CE shall be required
to provide any required equity not
so contributed by Distral. If
agreed by the Parties and
acceptable to project lenders,
equity contributions may be made in
the form of equipment supplied or
construction or other services
performed. Development costs
incurred by the Parties may be
considered equity contributions to
the extent agreed by the Parties
and permitted by the applicable
project lender. Either Party's
commitment to invest equity is
conditioned upon obtaining
acceptable rates of return and
other acceptable provisions.
Profit/Loss/Distributions,
Development Fees and
EPC Contingencies: All profits, losses and distributions
(other than reimbursements incurred by
the Parties, the Joint Venture or a
Project Company) shall be allocated in
accordance with each Party's equity
contribution or according to the
provisions of the Project Company's
organizational documents. Any
development fees shall be shared on a
50/50 basis regardless of the Parties'
equity contributions. Any turnkey
construction contract contingency
available to the Parties shall be
allocated in accordance with each
Parties' equity contributions.
Assignment: Except for assignments to wholly owned
subsidiaries and Lancaster Steel Co.,
Inc. and Distral Termica C.A., neither
Party may sell, transfer, assign or
otherwise encumber any portion of its
interest in the Joint Venture or a
Project Company without the other
Party's prior written consent; provided,
however, that CE may assign up to 50% of
its equity interest in any power project
or Project Company (but not the Joint
Venture) to Kiewit or an affiliate
thereof.
Accounting: The records of the Joint Venture and
each Project Company shall be accurate
in all material respects and shall
fairly present the position and results
of the Joint Venture and each Project
Company and shall be prepared on an
accrual basis in accordance with U.S.A.
generally accepted accounting principles
consistently applied, although, if
applicable, the Joint Venture shall also
prepare financial statements for a
particular Project Company in the manner
mandated by local law in the country in
which the project is located.
Management: The Joint Venture shall be governed by a
management committee consisting of 4 senior
executive members including the President of
each Party, 2 selected by CE and 2 selected
by Distral. Each Project Company shall be
governed by a management committee, board of
directors or such other body as is
appropriate consisting of members selected
roughly on the basis of each Party's
proportionate ownership. The management
committee, board or other governing body
shall transact business on the basis of the
vote of a majority of its members. The
management committee shall appoint one person
as the project manager to oversee the
development and one person as the project
manager to oversee the construction of each
power project; provided, however, that no
person or Party may bind the Joint Venture or
the other Party without the prior written
consent of the management committee.
Prompt and Informed
Decisions: The Parties agree to use all reasonable
efforts to act promptly on project
proposals and to make Management
Committee decisions to pursue or reject
particular projects within 10 business
days of receiving reasonably detailed
and adequate information regarding a
particular project. The Parties
understand that certain local laws and
regulations (and certain regulations and
requirements of international financing
entities) cannot be modified and
therefore the Parties agree to use all
reasonable efforts to clearly understand
the implications of such laws,
regulations and requirements (and
otherwise properly inform themselves)
prior to their management committee
representatives making a decision to
pursue a particular project.
Both Parties agree to use all reasonable
efforts so that any necessary decisions of
their Boards of Directors will be obtained in
a prompt and expeditious manner so as to
avoid disrupting any near pending proposals
and/or negotiations.
Additional Participants: To the extent the bid qualification
requirements of a power project
require participation by entities
having certain categories of
expertise or experience not
available to a Party, the Parties
will use their reasonable efforts
to bring in additional joint
venture participants having such
expertise or experience under
mutually acceptable terms.
Term: The initial term of the Joint Venture
shall be 3 years, but shall extend
automatically for successive terms of
one year, but only for the sole purpose
of considering identified power projects
not yet rejected or pursuing power
projects already accepted for
development by the management committee.
The term of each Project Company shall
be as set forth in its organizational
documents which shall establish a term
at least as long as is required to
complete the development, construction
and operation of its respective power
project. This Joint Venture agreement
shall terminate upon a party becoming
insolvent or making any assignment for
the benefit of its creditors, or in any
way becoming the subject of a petition
in bankruptcy or the appointment of a
trustee or receiver.
Discontinuance: Except for binding obligations under
executed construction, operations, or
equipment supply agreements with respect
to any power project, either Party may
elect to discontinue its participation
in the Joint Venture or any project or
Project Company by notifying the other
Party of its intent to so discontinue;
provided that such discontinuance shall
not disrupt any near term pending
proposals and/or negotiations such that
the remaining Party cannot continue with
the proposal/negotiations. Upon
delivery of such notice the Parties
shall, for no additional consideration,
execute appropriate assignment,
assumption and release documents which
evidence the termination of the Joint
Venture or the discontinuing Party's
project or Project Company
participation, as applicable, and
thereafter each Party shall be free to
pursue power projects independently,
known or unknown, without limitation.
Such notice of discontinuance shall be
effective as a termination of the Joint
Venture or the discontinuing Party's
participation in a project or Project
Company; however, the discontinuing
Party shall pay its proportionate share
of expenses incurred by the Joint
Venture or Project Company on or before
the date of such discontinuance as such
expenses come due in the ordinary course
of events. The discontinuing Party
shall receive repayment of all
development costs incurred and paid by
it prior to the date of discontinuance
by such Party at the time the Joint
Venture or a Project Company is entitled
to draw on construction or project
financing with respect to such power
project.
The Parties acknowledge that after management
committee approval of a particular project
proposal, they shall each use all reasonable
efforts to ensure that discontinuance by a
Party of participation in a project shall
only be made for good business reasons and
the Parties further acknowledge that a change
in the top management structure of either
Party or its affiliates shall be considered a
good business reason for discontinuance of
participation in this Joint Venture or any
project.
Cooperation: The Parties shall attempt to cooperate
in other power projects located
throughout the world including the
United States which are not subject to
this agreement. Such cooperation shall
be non-exclusive, but where reasonably
practical each Party will discuss
potential joint development or other
participating relationships with respect
to world wide power project
opportunities. Except for power
projects in the Caribbean, South America
and that part of Central America south
of Mexico, each Party shall have the
right to independently engage in the
development of power projects without
consulting the Joint Venture or the
other Party.
Compliance with Law: In performing their respective
activities hereunder, each Party agrees
to comply with all applicable United
States, Columbian and other applicable
laws. In this regard, each Party agrees
that neither it nor its employees,
agents or subcontractors, shall make any
payment or give anything of value to any
government official to influence a
government decision, or to gain any
other governmental advantage for the
Parties, the Joint Venture or a Project
Company in connection with the work
performed hereunder.
This Joint Venture Agreement has been duly authorized and
executed by each Party and is intended to be a legally binding
and enforceable agreement under, and governed by, the laws of
the state of New York, U.S.A.
Dated as of: December 14, 1993
Distral S.A. California Energy
Company, Inc.
By: By:
Algis Didziulis, President David L. Sokol, President
Exhibit 11.0
California Energy Company, Inc.
Calculation of Earnings per share in Accordance
with Interpretive Release No. 34-9083
for the three years ended December 31, 1993
(dollars in thousands, except per share amounts)
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Actual weighted average shares
outstanding for the period 35,454,539 33,414,129 29,847,156
Dilutive stock options and warrants using
average market prices 3,030,431 3,330,618 4,844,869
Preferred stock --- 786,712 779,405
Total number of shares based on shares
outstanding and the assumption that dilutive
stock options and warrants will be exercised
at average stock market prices 38,484,971 37,531,469 35,470,430
Additional dilutive stock options and
warrants using ending market price --- 1,282,223 992,394
Total shares based on shares outstanding and
the assumption that dilutive stock options
and warrants will be exercised at ending
market price. 38,484,971 38,813,692 36,463,829
Income before change in accounting
principle and extraordinary item $ 43,074 $ 38,810 $ 26,582
Cumulative effect of change in accounting
principle. 4,100 --- ---
Extraordinary item --- (4,991) ---
Net income 47,174 33,819 26,582
Less: Series C preferred stock dividends (4,630) (4,275) ---
Net Income available for common shares $ 42,544 $ 29,544 $ 26,582
Primary earnings per share before change in
accounting principle and extraordinary item $ 1.00 $ .92 $ .75
Primary earnings per share $ 1.11 $ .79 $ .75
Fully diluted earnings per share before change
in accounting principle and extraordinary item
based on SEC Interpretive Release No. 34-9083 $ 1.00 $ .89 $ .73
Fully diluted earnings per share based
on SEC interpretive release No. 34-9083 $ 1.11 $ .76 $ .73
</TABLE>
EXHIBIT 13
<TABLE>
Selected Financial Data
amounts in thousands except per share data
YEAR ENDED DECEMBER 31
<CAPTION>
1993 1992 1991 1990 1989
<S> <C> <C> <C> <C> <C>
Sales of electricity $129,861 $115,087 $104,155 $89,026 $43,010
Sales of steam 2,198 2,255 2,029 ---- ----
Other income 17,194 10,187 9,379 7,787 5,386
Expenses 87,995 76,797 80,697 81,248 35,345
Income before provision for
income taxes 61,258 50,732 34,866 15,565 13,051
Income before change in
accounting principle and
extraordinary item 43,074 38,810 26,582 12,043 10,336
Cumulative effect of change
in accounting principle 4,100 ---- ---- ---- ----
Extraordinary item ---- (4,991) ---- ---- ----
Preferred dividends 4,630 4,275 ---- ---- ----
Net income 47,174 33,819 26,582 12,043 10,336
Income per share before change
in accounting principle and
extraordinary item 1.00 .92 .75 .44 .38
Cumulative effect of change in
accounting principle .11 ---- ---- ---- ----
Extraordinary item per share ---- (.13) ---- ---- ----
Net income per share 1.11 .79 .75 .44 .38
Total assets 715,984 580,550 517,994 393,853 349,282
Total liabilities 425,393 336,272 298,146 331,134 305,265
Deferred income 20,288 21,164 22,015 2,926 1,854
Redeemable preferred stock 58,800 54,350 54,705 4,705 ----
Stockholders' equity 211,503 168,764 143,128 55,088 42,163
Common stock cash dividends ---- ---- ---- ---- ----
</TABLE>
Management's Discussion and Analysis of
Financial Condition and Results of Operations
dollars and shares in thousands except per share data
The following is Management's discussion and analysis of certain
significant factors which have affected the Company's financial
condition and results of operations during the periods included
in the accompanying statements of operations.
General
For purposes of consistency in financial presentation, the Plants
comprising the Coso Project (including the Navy I, Navy II, and
BLM Plants) capacity factors are based upon a capacity amount of
88 gross MW ("GMW")/80 net MW ("NMW") for each plant. The Navy
I and Navy II Plants each consist of a set of three turbines
located at a plant site. The BLM Plant consists of two turbines
at one site ("BLM East") and one turbine at another site ("BLM
West"). In April 1990, the Company completed a retrofit of the
two turbines at BLM East and in July 1990 completed associated
retrofitting of the cooling towers to increase the aggregate
installed capacity of the BLM Plant to 88 GMW/80 NMW, effective
July 2, 1990. Each Plant possesses an operating margin which
periodically allows for production in excess of the amount listed
above. However, through 1990, the Navy I, Navy II and BLM Plant
capacity amounts were restricted by the then existing PURPA
80NMW cap. With the lifting of the PURPA 80NMW cap in 1991,
utilization of this operating margin can, at times, produce plant
capacity factors in excess of 100%. Utilization of this
operating margin is based upon a variety of factors and can be
expected to vary throughout the year under normal operating
conditions.
Results of Operations
Three Years Ended December 31, 1993, 1992 and 1991
Sales of electricity and steam increased to $132,059 in the year
ended December 31, 1993 from $117,342 in the year ended December
31, 1992, a 12.5% increase. This improvement was primarily due
to a 9.1% increase in Coso Project's electric kWh sales to
2,186.7 million kWh from 2,004.0 million kWh, and an increased
price per kWh in accordance with the SO4 agreements. The
increase in Coso Project kWh sales was primarily due to the
completion of new production wells. The increase in sales of
electricity and steam in 1992 to $117,342 from $106,184 in 1991
was primarily due to increasing electric kWh sales by 6.0% to
2,004.0 million kWh from 1,890.4 million kWh largely as a result
of the drilling of additional production wells, and the
aforementioned increase in price per kWh pursuant to the SO4
Agreements.
The following operating data includes the full capacity and
electricity production of the Coso Project only:
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Overall Capacity Factor 104.0% 95.1% 89.9%
kWh Produced 2,186,700,000 2,004,000,000 1,890,402,000
Installed Capacity NMW
(Average) 240 240 240
</TABLE>
The overall Coso Plant capacity factor was 108.8% in the fourth
quarter of 1993 compared to 109.1%, 100.9% and 97.1% for the
third, second and first quarters of 1993, respectively. The Navy
I Plant capacity factor was 111.2% in 1993, compared to 99.8% and
98.5% in 1992 and 1991, respectively.
The Navy II Plant capacity factor was 102.6% in 1993 compared to
98.1% and 99.9% in 1992 and 1991, respectively. The BLM Plant
capacity factor was 98.1% in 1993 compared to 87.2% and 71.4% in
1992 and 1991, respectively. The BLM Plant, Navy I Plant and the
Navy II Plant were overhauled in conjunction with scheduled
warranty inspections in 1993, 1992 and 1991 respectively,
resulting in a temporary reduction of the plant capacity factor
of 3% in the specified year.
Electric sale price per kWh for the Coso Project varies
seasonally in accordance with the rate schedule included in the
SO4 Agreements. The price consists of an energy payment based
on the annualized contracted rate of 10.11 cents per kWh in 1993,
9.23 cents per kWh in 1992, and 8.58 cents per kWh in 1991, and
constant annual capacity payments of which the Company's share
was $5,400 to $5,800 per annum for each of the three power
plants. Capacity payments are significantly higher in the months
of June through September. Bonus payments are received monthly,
of which the Company's share was approximately $1,000 per annum
for each of the three power plants.
The Coso Project's average electricity prices per kWh in 1993,
1992 and 1991 were comprised of (in cents):
Energy Capacity & Bonus Total
Average fiscal 1993 10.11 1.93 12.04
Average fiscal 1992 9.23 2.10 11.33
Average fiscal 1991 8.58 2.24 10.82
The Desert Peak and Roosevelt Hot Springs facilities ran at or
near capacity levels for each of the past three years.
Steam sales from the Roosevelt Hot Springs field, which was
acquired in January, 1991, remained relatively unchanged at
$2,198, $2,255, and $2,077 in 1993, 1992, and 1991, respectively.
Electric sales from Desert Peak were $5,177, $5,347 and $3,976
for the years 1993, 1992, and 1991, respectively. Desert Peak
was acquired in March 1991 and, accordingly, reflects only nine
months sales in 1991.
Interest and other income increased in 1993 to $17,194 from
$10,187 in 1992 and from $9,379 in 1991. The increase reflects
higher average cash balances, interest income on notes receivable
from the Coso Joint Ventures and interest income on the Company's
share of the cash reserves established in the refinancing of the
Coso Project debt in December, 1992.
The Company's cost per kWh* was as follows (in cents):
1993 1992 1991
Plant operations (net of Company's
operator fees) 1.64 1.65 1.77
General and administration 1.03 1.04 1.11
Royalties .65 .61 .49
Depreciation and amortization 1.39 1.33 1.31
Interests, less amounts capitalized 1.82 1.17 2.16
TOTAL 6.53 5.80 6.84
*Cost per kWh includes electrical production from the Desert Peak facility and
the electrical production equivalent of the Company's share of geothermal steam
produced at the Roosevelt Hot Springs field, acquired in March and January
1991, respectively.
The Company's expenses* as a percentage of sales of electricity
and steam were as follows:
1993 1992 1991
Plant operations (net of Company's
operator fees) 15.8% 17.7% 18.8%
General and administration 10.0 11.1 11.7
Royalties 6.3 6.6 5.2
Depreciation and amortization 13.5 14.3 13.9
Interests, less amounts capitalized 17.7 12.7 23.0
TOTAL 63.3% 62.4% 72.6%
*Expenses as a percentage of electricity sales and steam sales include
electricity sales from the Desert Peak facility and steam sales from the
Roosevelt Hot Springs field, acquired in March and January 1991, respectively.
The Company's expenses, excluding interest, increased as a
general result of the greater electricity production of the Coso
Project. However, in 1993, plant operations and general and
administration costs per kWh decreased from 1992. In 1992, the
Company's total expenses, excluding interest, were proportionally
less than the increase in electricity production of the Coso
Project.
The cost of plant operations increased to $25,362 in 1993 from
$24,440 in 1992, an increase of 3.8%. The cost of plant
operations increased to $24,440 in 1992 from $23,525 in 1991, an
increase of 3.9%. General and administration costs remained
relatively unchanged at $13,158 in 1993 compared to $13,033 in
1992. General and administration costs increased to $13,033 in
1992 from $12,476 in 1991, a 4.5% increase. However, for 1993
and 1992 both plant operations and general and administration
costs per kWh continued to decrease due to a proportionally
greater increase in electrical production than plant operations
and general administration costs. Plant cost per kWh decreased
to 1.64 cents in 1993 from 1.65 cents in 1992 and 1.77 cents in
1991. General and administration cost per kWh decreased to 1.03
cents in 1993 from 1.04 cents in 1992 and 1.11 cents in 1991.
Royalty costs increased to $8,274 in 1993 from $7,710 in 1992,
an increase of 7.3%. Royalty costs increased to $7,710 in 1992
from $5,505 in 1991, an increase of 40.1%, due to higher
electrical sales and a contractually scheduled increase in the
1992 royalty rate for the second and third turbines of the Navy
I Plant. Overall, the royalty cost per kWh increased to 0.65
cents in 1993 from 0.61 cents in 1992 and 0.49 cents in 1991.
Depreciation and amortization expense increased to $17,812 in
1993 from $16,754 and $14,752 in 1992 and 1991, respectively, a
6.3% increase from 1992 to 1993, and a 13.6% increase from 1991
to 1992. Depreciation and amortization expense for 1993 was 1.39
cents per kWh compared to 1.33 cents in 1992 and 1.31 cents per
kWh in 1991. The increase in 1993 was due to additional
capitalized costs associated with the settlement of litigation
involving Mission Power Engineering Company ("MPE") and the
Mission Power Group, as well as additional wells and gathering
systems. The increase in per kWh cost in 1992 was due largely
to the costs of an increased number of production and injection
wells.
Interest expense, less amounts capitalized, increased to $23,389
in 1993 from $14,860 in 1992, an increase of 57.4%, or 1.82 cents
per kWh in 1993, compared to 1.17 cents in 1992. Net interest
expense decreased to $14,860 in 1992 from $24,439, or 2.16 cents
per kWh in 1991. Net interest expense in 1993 increased due
primarily to the Company's higher weighted average interest rate,
higher levels of indebtedness associated with the Coso Project
and the issuance of convertible subordinated debentures in June
1993. The short-term variable rate debt on the Coso Project was
refinanced in 1992 with longer-term fixed rate debt. The
weighted average interest rate on the Coso Project debt was 7.9%,
5.4%, and 8.5% in 1993, 1992, and 1991 respectively. Net
interest expense decreased in 1992 from 1991 as a result of low
interest rates associated with the Coso Project's then variable
rate debt.
The provision for income taxes increased to $18,184 in 1993 from
$11,922 and $8,284 in 1992 and 1991, respectively. The effective
tax rate was 29.7%, 23.5% and 23.8% in 1993, 1992, and 1991. The
increase in the 1993 effective tax rate was a result of adopting
Financial Accounting Standard 109 ("FAS 109").
Income before the provision for income taxes increased 21% to
$61,258 in 1993 from $50,732 in 1992. Net income after a
cumulative effect of a change in accounting principle was $47,174
and net income available to common shareholders was $42,544 or
$1.11 per common share for the year ended December 31, 1993.
This compares to net income of $33,819 after an extraordinary
item and net income available to common shareholders of $29,544
or $.79 per common share for the year ended December 31, 1992.
Net income before cumulative effect of a change in accounting
principle for the year ended December 31, 1993 was $43,074 or
$1.00 per common share versus net income before an extraordinary
item of $38,810 or $.92 per common share in 1992. In 1991,
income before the provision for income taxes was $34,866 and net
income available to common shareholders was $26,582, or $.75 per
share.
Earnings per share were favorably impacted in 1992 by the
Company's repurchase of common shares during 1992 at an average
price of approximately $12.00 per share. The Company purchased
common shares to be held as treasury stock which were reissued
upon the exercise of options and warrants.
Liquidity and Capital Resources
The Company's cash and short-term investments were $127,756 at December
31, 1993 as compared to $54,671 at December 31, 1992. In addition,
the Coso Project retained cash and investments on project control
accounts of which the Company's share was $14,943 and $8,848 at
December 31, 1993 and 1992, respectively. Distributions out of
the project control accounts are made monthly to the Company for
operation and maintenance and capital costs and semiannually to
each Coso Joint Venture partner for profit sharing under a
prescribed calculation subject to mutual agreement by the
partners. In addition to these liquid instruments, the Company
recorded separately restricted cash of $48,105 and $62,514 at
December 31, 1993 and 1992, respectively. The restricted cash
balance in 1993 was comprised primarily of the Company's
proportionate share of Coso Project cash reserves for debt
reserve funds and in 1992 included a contingency reserve fund,
both of which were established in conjunction with the Coso
Project's refinancing of its previous bank debt.
Accounts receivable normally represents two months of revenues,
and fluctuates with both production and price per kWh.
The balance due from/to the Coso Joint Ventures relates to
operations, maintenance, and management fees for managing the
Coso Project. This amount fluctuates based on the timing of
billings and incurrence of costs.
In December 1992, the Company refinanced the existing bank debt
of the Coso Project (see Note 5 of the Notes to the Consolidated
Financial Statements). Coso Funding Corp. ("Funding Corp."), a
single-purpose corporation, was formed to issue $560,245 of notes
for its own account and as an agent acting on behalf of Navy I,
BLM and Navy II Plants. The proceeds were used in part to
replace the outstanding Coso Project bank indebtedness and to
provide funding within the Coso Project for certain reserves.
As of December 31, 1993 and 1992 the Company's proportionate
share of the Coso Project loan was $246,880 and $263,604,
respectively.
The Funding Corp. notes have remaining terms of up to eight years
and different fixed interest rates for each tranche. The
underlying project loans have identical terms as the Coso Project
loans and are also non-recourse to the Company.
In connection with the Coso Project refinancing, the Company
purchased Community Energy Alternatives Incorporated's ("CEA")
interest in the Coso Project at the close of the Coso Project
refinancing. See Note 5 of the Notes to the Consolidated
Financial Statements.
On June 9, 1993, MPE and the Mission Power Group, subsidiaries
of SCECorp., and the Coso Joint Ventures reached a final
settlement of all of their outstanding disputes and claims
relating to the construction of the Coso Project. As a result
of the various payments and releases involved in such settlement,
the Coso Joint Ventures agreed to make a net payment of $20,000
to MPE from the cash reserves of the Coso Project contingency
fund and MPE agreed to release its mechanics' liens on the Coso
Projects. After making the $20,000 payment, the remaining
balance of the Coso Project contingency fund (approximately
$49,300) was used to increase the Coso Project debt reserve fund
from approximately $43,000 to its maximum fully-funded
requirement of $67,900. The remaining $24,400 balance of the
contingency fund was retained within the Coso Project for future
capital expenditures and for Coso project debt service payments.
Since the Coso Project debt service reserve is fully funded in
advance, Coso Project cash flows otherwise intended to fund the
Coso Project debt service reserve funds, subject to satisfaction
of certain covenants and conditions contained in the Coso Joint
Ventures' refinancing documents, are available for distribution
to the Company in is proportionate share.
On May 3, 1993, the transmission line dispute was settled and the
transmission line deposit of approximately $7,700 was released
to the Company.
In June of 1993, the Company issued $100,000 principal amount of
5% convertible subordinated debentures (the "Convertible
Subordinated Debentures") due July 31, 2000. The Convertible
Subordinated Debentures are convertible into shares of the
Company's common stock at any time prior to redemption or
maturity at a conversion price of $22.50 per share, subject to
adjustment in certain circumstances. Interest on the Convertible
Subordinated Debentures is payable semi-annually in arrears on
July 31 and January 31 each year, commencing on July 31, 1993.
The Convertible Subordinated Debentures are redeemable for cash
at any time on or after July 31, 1996 at a redemption price of
(expressed in percentages of the principal amount) 102%, 101%,
100% and 100% in 1996, 1997, 1998 and 1999, respectively. The
Convertible Subordinated Debentures are an unsecured general
obligation of the Company and subordinated to all existing and
future senior indebtedness of the Company.
The Senior Notes, of which $35,730 aggregate principal amount are
currently outstanding, mature in March 1995 and bear interest at
the rate of 12% per annum, plus contingent interest, calculated
by reference to the Company's share of the cash flow from the
Coso Project through December 31, 1994. Simultaneous with the
closing of a proposed offering of Senior Discount Notes (see Note
16 of the Notes to the Consolidated Financial Statements), the
Company intends to use approximately $39,000 to defease and
provide for the repayment of the entire aggregate principal
amount of Senior Notes outstanding. The Senior Notes prohibit
the payment of cash dividends unless the Company has a net worth
of at least $50,000 after payment of such dividends, and
dividends do not exceed 50% of accumulated net income subsequent
to December 31, 1987. The Senior Notes also place restrictions
on capital expenditures not related to the Coso Project.
Proceeds and benefits from warrants and options for shares of
common stock exercised in 1993 and 1992 aggregated approximately
$1,400 and $8,065, respectively. In addition, in September 1993,
the Company acquired The Ben Holt Co. ("BHC"), a thirty person
engineering firm for a combination of cash and Company stock.
In connection with this transaction, 87 shares were issued having
an aggregate market value of $1,557.
The Company repurchased 157 common shares during 1993 for the
aggregate amount of $2,897. The Company purchased common stock
to be held as treasury stock in anticipation of their reissue
upon the exercise of options. The Company repurchased 565 shares
of common stock in 1992 at an aggregate amount of $4,887. The
shares were reissued during 1992 upon the exercise of stock
options.
On October 13,1992, the Company repurchased, and cancelled,
certain warrants exercisable for 1,025 shares of unregistered
common stock at $2.04 per share, for a purchase price of $9.16
per share, or approximately $9,389 in aggregate. Kiewit Energy
Company ("Kiewit Energy") simultaneously purchased and exercised
other warrants to purchase 600 shares of unregistered common
stock at $2.04 per share, providing the Company with proceeds of
$1,200. On October 27, 1992, the Company repurchased and
cancelled warrants exercisable for 250 shares of unregistered
common stock at $2.04 per share, for a purchase price of $9.316
per share, or $2,329 in aggregate.
On November 15, 1992, the Company called the Company's Series B
convertible preferred stock, no par value (the "Series B
preferred stock"), for conversion into common stock. Each share
of Series B preferred stock was converted into two shares of
common stock and, accordingly, the Company issued 954.9 shares
of common stock.
In 1991, the Company and Kiewit Energy signed a Stock Purchase
Agreement and related agreements (see Note 12 to the Consolidated
Financial Statements). In addition, in 1991 the Company issued
one thousand shares of its Series C redeemable preferred stock
to Kiewit Energy for $50,000 per share.
On March 31, 1993, the Company acquired leases from Unocal on
26,000 acres of geothermal properties at the Glass Mountain site
in Northern California which includes three successful production
wells.
The Company is actively engaged in the acquisition of, and is
seeking to develop, construct, own and operate power projects
utilizing geothermal and other technologies, both domestically
and internationally, the completion of any of which is subject
to substantial risk. The Company is currently pursuing a number
of international power project opportunities in countries where
private power generation programs have been initiated, including
the Philippines and Indonesia. Development can require the
Company to expend significant sums for preliminary engineering,
permitting, legal and other expenses in preparation for
competitive bids which the Company may not win or before it can
be determined whether a project is feasible, economically
attractive or financeable. Successful development is contingent
upon, among other things, negotiation of construction, fuel
supply and power sales contracts with other project participants
on terms satisfactory to the Company, and receipt of required
governmental permits and consents. Further, there can be no
assurance that the Company will obtain access to the substantial
debt and equity capital required for the acquisition or
development and construction of electric power projects. To the
extent the Company engages in international development efforts,
the financing and development of projects entails significant
political and financial risks (including, without limitation,
uncertainties associated with first time privatization efforts
in the countries involved, currency exchange rate fluctuations,
currency repatriation restrictions, political instability, civil
unrest and expropriation) and other structuring issues that have
the potential to cause substantial delays or that the Company may
not be fully capable of insuring against. There can be no
assurance that development efforts on any particular project, or
the Company's acquisition or development efforts generally, will
be successful.
In particular, the Company is developing a number of
international projects, for which it may have significant capital
requirements. In 1994, the Company intends to incur capital
expenditures in excess of $40,000 for international project
development. In addition to its international projects, the
Company plans to incur domestic geothermal capital expenditures
in the approximate aggregate amount of $30,000 in 1994. The
Company's planned capital spending includes, among other things,
its share of recurring Coso Project capital expenditures, as well
as development of the Newberry Project in the Pacific Northwest.
The Company is constructing the Yuma Project, a 50 MW natural gas
fired cogeneration project in Yuma, Arizona. Engineering and
equipment procurement commenced in 1993. Capital expenditures
of $10,000 are anticipated through the completion of the Yuma
Project by mid year 1994. The capital expenditures will be
funded from existing cash balances and the Company's operating
cash flows.
Inflation has not had a substantial impact on the Company's
operating revenues and costs. The Coso Project's energy payments
for electricity will continue to be based upon scheduled rate
increases through the initial ten-year period of each SO4
Agreement. Prior to the Coso Project refinancing, the Project
Loans relating to the Coso Project were generally for periods up
to twelve months at LIBOR plus a specified margin. Accordingly,
the interest rates on the loans varied and over the operating
period resulted in fluctuating interest payments. The refinanced
Coso Project debt has fixed interest rates.
Adoption of Financial Accounting Standard No. 109
On January 1, 1993, the Company adopted FAS 109. The adoption
of FAS 109 changes the Company's method of accounting for income
taxes from the deferred method as required by Accounting
Principles Board No. 11 to an asset and liability approach. Under
FAS 109, the net excess deferred tax liability as of January 1,
1993 was determined to be $4,100. This amount is reflected in
1993 income as the cumulative effect of a change in accounting
principle. It primarily represents the recognition of the
Company's tax credit carryforwards as a deferred tax asset.
There was no cash impact to the Company upon the required
adoption of FAS 109. Under FAS 109, the effective tax rate
utilized increased at the time of adoption as a result of the tax
credit carryforwards being recognized as an asset and unavailable
to reduce the current period's effective tax rate for computing
the Company's provision for income taxes. The effective tax rate
continues to be less than the statutory rate primarily due to the
depletion deduction and the generation of energy credits in 1993.
The significant components of the deferred tax liability are the
temporary differences between the financial reporting bases and
income tax bases of the power plant and the well and resource
development costs, and in addition, the offsetting benefits of
operating loss carryforwards and investment and geothermal energy
tax credits and alternative minimum tax carryforwards.
CONSOLIDATED BALANCE SHEETS
as of December 31, 1993 and December 31, 1992
dollars and shares in thousands, except per share amounts
ASSETS 1993 1992
Cash and investments $ 127,756 $ 54,671
Joint venture cash and investments (Note 5) 14,943 8,848
Restricted cash (Notes 4 and 5) 48,105 62,514
Accounts receivable 21,658 16,172
Transmission line deposit (Note 13) --- 7,684
Due from Joint Ventures 1,394 ---
Geothermal power plant and development costs,
net (Notes 4 and 5) 458,974 389,646
Equipment, net of accumulated depreciation of
$4,773 and $3,996 4,540 4,312
Notes receivable - Joint Ventures (Note 13) 11,280 9,997
Deferred charges and other assets 27,334 26,706
_________ _________
Total assets $ 715,984 $ 580,550
LIABILITIES AND STOCKHOLDERS' EQUITY
Liabilities:
Accounts payable $ 607 $ 3,146
Other accrued liabilities 19,866 18,111
Income taxes payable (Note 8) 4,000 ---
Project finance loans (Note 5) 246,880 263,604
Due to Joint Ventures --- 469
Senior notes (Note 6) 35,730 35,730
Convertible subordinated debentures (Note 7) 100,000 ---
Deferred income taxes 18,310 15,212
_________ _________
Total liabilities 425,393 336,272
Deferred income (Note 4) 20,288 21,164
Commitments and contingencies (Notes 3, 6, 9, 13 and 16)
Redeemable preferred stock (Note 10) 58,800 54,350
Stockholders' equity (Notes 11 and 12):
Preferred stock - authorized 2,000 shares,
no par value (Note 10) --- ---
Common stock - authorized 60,000 shares,
par value $0.0675 per share
issued and outstanding 35,446 and 35,258 shares 2,404 2,380
Additional paid in capital 100,965 97,977
Retained earnings 111,031 68,407
Treasury stock - 157 common shares at cost (2,897) ---
_________ _________
Total stockholders' equity 211,503 168,764
_________ _________
Total liabilities and
stockholders' equity $ 715,984 $ 580,550
The accompanying notes are an integral part of these financial statements.
<TABLE>
CONSOLIDATED STATEMENTS OF OPERATIONS
for the three years ended December 31, 1993
dollars and shares in thousands, except per share amounts
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Revenue:
Sales of electricity and steam $132,059 $117,342 $106,184
Interest and other income 17,194 10,187 9,379
________ ________ ________
Total revenues 149,253 127,529 115,563
Cost and expenses:
Plant operations 25,362 24,440 23,525
General and administration 13,158 13,033 12,476
Royalties 8,274 7,710 5,505
Depreciation and amortization 17,812 16,754 14,752
Interest 30,205 20,459 29,814
Less interest capitalized (6,816) (5,599) (5,375)
________ ________ ________
Total expenses 87,995 76,797 80,697
Income before provision for income taxes 61,258 50,732 34,866
Provision for income taxes (Note 8) 18,184 11,922 8,284
Income before change in accounting principle
and extraordinary item 43,074 38,810 26,582
Cumulative effect of change in accounting
principle (Note 8) 4,100 --- ---
Extraordinary item (Note 15) --- (4,991) ---
Net income 47,174 33,819 26,582
Preferred dividends 4,630 4,275 ---
Net income available to common stockholders $42,544 $29,544 $26,582
Income per share before change in accounting
principle and extraordinary item $ 1.00 $ .92 $ .75
Cumulative effect of change in accounting
principle (Note 8) .11 --- ---
Extraordinary item (Note 15) --- (.13) ---
Net income per share $ 1.11 $ .79 $ .75
Average number of shares outstanding 38,485 37,495 35,471
</TABLE>
The accompanying notes are an integral part of these financial statements.
<TABLE>
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
for the three years ended December 31, 1993
dollars and shares in thousands
<CAPTION>
Outstanding Additional
Common Common Paid-In Retained Treasury
Shares Stock Capital Earnings Stock Total
<S> <C> <C> <C> <C> <C> <C>
Balance January 1, 1991 23,218 $ 1,567 $ 39,353 $ 14,168 $ --- $ 55,088
Exercise of stock options 2,329 157 14,959 --- --- 15,116
Sale and private placement
of common stock (Note 12) 6,505 439 43,237 --- --- 43,676
Exercise of warrants 660 45 2,897 --- --- 2,942
Issue costs of sale of preferred stock --- --- (276) --- --- (276)
Net income --- --- --- 26,582 --- 26,582
Balance December 31, 1991 32,712 2,208 100,170 40,750 --- 143,128
Exercise of stock options 1,544 67 2,764 --- --- 2,831
Exercise of warrants 612 41 1,206 --- --- 1,247
Issue costs on stock --- --- (96) --- --- (96)
Purchases/issuances of treasury stock
for exercise of options and warrants,
net of proceeds of $797 (565) --- (4,090) --- --- (4,090)
Preferred stock dividends, Series B & C,
including cash distributions of $134 --- --- --- (6,162) --- (6,162)
Retirement of warrants --- --- (11,716) --- --- (11,716)
Tax benefit from stock plan --- --- 3,420 --- --- 3,420
Net income before preferred dividends --- --- --- 33,819 --- 33,819
Conversion of preferred stock
to common stock 955 64 6,319 --- --- 6,383
Balance December 31, 1992 35,258 2,380 97,977 68,407 --- 168,764
Exercise of stock options 258 18 937 --- --- 955
Issuance of stock for purchase of
The Ben Holt Co. 87 6 1,551 --- --- 1,557
Purchase of treasury stock (157) --- --- --- (2,897) (2,897)
Preferred stock dividends, Series C,
including cash distributions of $100 --- --- --- (4,550) --- (4,550)
Tax benefit from stock plan --- --- 500 --- --- 500
Net income before preferred dividends --- --- --- 47,174 --- 47,174
Balance December 31, 1993 35,446 $ 2,404 $100,965 $111,031 $ (2,897) $211,503
</TABLE>
The accompanying notes are an integral part of these financial statements.
<TABLE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
for the three years ended December 31, 1993
dollars in thousands
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Cash flows from operating activities:
Net income $ 47,174 $33,819 $26,582
Adjustments to reconcile net cash flow from operating activities:
Depreciation and amortization 17,812 16,754 14,752
Amortization of deferred financing costs 1,013 967 1,054
Expense of previously deferred financing costs --- 3,895 ---
Provision for deferred income taxes 3,098 3,645 5,889
Other --- --- (639)
Changes in other items:
Accounts receivable (5,486) 1,279 (3,701)
Accounts payable and other accrued liabilities (784) (7,082) (10,890)
Deferred income (876) (851) (589)
Income tax payable 4,000 (1,202) 713
Other assets (177) 814 (2,157)
________ _______ _______
Net cash flows from operating activities 65,774 52,038 31,014
Cash flows from investing activities:
Capital expenditures relating to power plants (10,295) (6,711) (112)
Well and resource development expenditures for existing projects (16,565) (19,203) (20,564)
Acquisition of equipment (1,104) (1,093) (773)
Acquisition of Nevada and Utah properties --- --- (43,062)
Pacific Northwest, Nevada, and Utah exploration costs (19,060) (4,145) (3,866)
Yuma - construction in progress (40,167) (1,294) ---
Transmission line deposit 7,684 (118) (1,404)
Decrease (increase) in restricted cash 14,409 9,882 (2,217)
Decrease (increase) in other investments 941 (14,503) ---
________ ________ ________
Net cash flows from investing activities (64,157) (37,185) (71,998)
Cash flows from financing activities:
Proceeds from sale of common, treasury and preferred
stocks and exercise of warrants and options 2,912 8,065 111,458
Repayment of project finance loans --- (17,098) (10,100)
Repayment of project loans (16,724) (6,277) ---
Retirement of project finance loans --- (204,210) ---
Payment of other senior notes --- --- (6,000)
Proceeds from refinancing --- 269,881 2,400
Proceeds from issue of convertible subordinated debentures 100,000 --- ---
Increase in restricted cash related to the refinancing --- (65,670) ---
Net change in short-term bank loan --- --- (15,000)
Deferred charges relating to debt financing (2,582) (2,937) (58)
Decrease (increase) in amounts due from Joint Ventures (3,146) 6,198 (6,180)
Purchase of warrants --- (11,716) ---
Proceeds from pre-sale of steam --- --- 20,317
Purchase of treasury stock (2,897) (4,887) ---
________ ________ ________
Net cash flows from financing activities 77,563 (28,651) 96,837
Net increase (decrease) in cash and investments 79,180 (13,798) 55,853
Cash and investments at beginning of period 63,519 77,317 21,464
________ ________ ________
Cash and investments at end of period $142,699 $63,519 $77,317
Interest paid (net of amounts capitalized) $20,136 $19,237 $24,435
Income taxes paid $6,819 $4,129 $1,682
</TABLE>
The accompanying notes are an integral part of these financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
for the three years ended December 31, 1993
dollars and shares in thousands, except per share amounts
1. BUSINESS
California Energy Company, Inc. (the "Company") was formed in
1971. It is primarily engaged in the exploration for and
development of geothermal resources and conversion of such
resources into electrical power and steam for sale to electric
utilities, and the development of other environmentally
responsible forms of power generation.
The Company has organized several partnerships and Joint
Ventures (herein referred to as Coso Joint Ventures) in order
to develop geothermal energy at the China Lake Naval Air
Weapons Station, Coso Hot Springs, China Lake, California.
Collectively, the projects undertaken by these Coso Joint
Ventures are referred to as the Coso Project. The Company is
the operator and holds interests between 46.4% and 50% in the
Coso Joint Ventures after payout. Payout is achieved when a
Coso Joint Venture has returned the initial capital to the
Coso Joint Venturers. In addition, the Company is exploring
geothermal resources in Northern California, Washington and
Oregon (collectively the Pacific Northwest). In January 1991,
the Company acquired a power plant and an interest in steam
fields in Nevada and Utah (See Note 4 Nevada and Utah
Properties). In 1992, the Company entered into the natural
gas-fired electrical generation market through the purchase of
a development opportunity in Yuma, Arizona. Commercial
operation of the Yuma project will commence in 1994. In 1993,
the Company started developing a number of international power
project opportunities where private power generating programs
have been initiated, including the Philippines and Indonesia.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements include the accounts of
the Company, its wholly-owned subsidiaries, and its
proportionate share of the Coso Joint Ventures in which it has
invested. All significant inter-enterprise transactions and
accounts have been eliminated.
Investments and Restricted Cash
Investments other than restricted cash are primarily
commercial paper and money market securities. The restricted
cash balance includes such securities and mortgage backed
securities, and is mainly composed of the Coso Joint Ventures'
debt service reserve funds. The debt service reserve funds
are legally restricted to their use and require the
maintenance of specific minimum balances. The carrying amount
of the investments approximates the fair value based on quoted
market prices as provided by the financial institution which
holds the investments.
Well, Resource Development and Exploration Costs
The Company follows the full cost method of accounting for
costs incurred in connection with the exploration and
development of geothermal resources. All such costs, which
include dry hole costs and the cost of drilling and equipping
production wells, as well as directly attributable
administrative and interest costs, are capitalized and
amortized over their estimated useful lives when production
commences. The estimated useful lives of production wells are
ten years each; exploration costs and development costs, other
than production wells, are generally amortized over the
weighted average remaining term of the Company's power and
steam purchase contracts. For purposes of current period
visibility and disclosure, all such costs are identified in
the Consolidated Statements of Cash Flows as they are
incurred.
Deferred Well and Rework Costs
Well rework costs are deferred and amortized over the
estimated period between reworks. These deferred costs of
$1,305 and $1,592 at December 31, 1993 and 1992, respectively,
are included in other assets. Currently, both production and
injection well reworks are amortized over twelve months.
Fixed Assets and Depreciation
The cost of major additions and betterments are capitalized,
while replacements, maintenance, and repairs that do not
improve or extend the lives of the respective assets are
expensed.
Depreciation of the operating power plants is computed on the
straight-line method over the estimated useful lives resulting
in a composite rate of depreciation of approximately 2.67% per
annum. Depreciation of furniture, fixtures and equipment,
which are recorded at cost, is computed on the straight-line
method over the estimated useful lives of the related assets,
which range from three to ten years.
Capitalization of Interest and Deferred Financing Costs
Prior to the commencement of operations, interest is
capitalized on the costs of the plants and geothermal resource
development to the extent incurred. Capitalized interest and
other deferred charges are amortized over the lives of the
related assets.
Deferred financing costs are amortized over the term of the
related financing. Loan fees are amortized using the implicit
interest method; other deferred financing costs are amortized
using the straight-line method. Accumulated amortization at
December 31, 1993 and 1992 was approximately $1,954 and $950,
respectively.
Revenue Recognition
Revenues are recorded based upon service rendered and
electricity and steam delivered to the end of the month.
Management Fee and Interest Revenue Recognition
The Company charges the Coso Joint Ventures management fees,
operator fees and interest on outstanding advances.
Recognition of fees and interest relating to power plants and
resource development of the Coso Joint Ventures in which the
Company has invested is deferred until each Coso Joint Venture
commences operations. Revenue previously deferred is
amortized over the lives of the related assets of the Coso
Joint Ventures as each Coso Joint Venture becomes operational.
Deferred Income Taxes
On January 1, 1993, the Company adopted Statement of Financial
Accounting Standard No. 109 ("FAS 109"), "Accounting for
Income Taxes". The adoption of FAS 109 changes the Company's
method of accounting for income taxes from the deferred method
as required by Accounting Principles Board Opinion No. 11 to
an asset and liability approach.
Net Income per Common Share
Earnings per common share are based on the weighted average
number of common and dilutive common equivalent shares
outstanding during the period computed using the treasury
stock method.
Cash Flows
The statement of cash flows classifies changes in cash
according to operating, investing, or financing activities.
Investing activities include capital expenditures incurred in
connection with the power plants, wells, resource development,
and exploration costs. The Company considers all investment
instruments purchased with a maturity of three months or less
to be cash equivalents. Restricted cash is not considered a
cash equivalent.
Reclassification
Certain amounts in the fiscal 1992 and 1991 financial
statements and supporting footnote disclosures have been
reclassified to conform to the fiscal 1993 presentation. Such
reclassification did not impact previously reported net income
or retained earnings.
3. INTEREST RATE SWAP AGREEMENTS
In January 1993, the Coso Joint Ventures entered into five
year deposit interest rate swap agreements which effectively
convert a notional deposit, the Company's portion of the
balance is $20,300 (restricted cash and investments), from a
variable rate to a fixed rate. The Company's proportion of
the deposit amount accretes annually to a maximum amount of
approximately $29,300 in 1996. Under the agreements, which
mature on January 11, 1998, the Coso Joint Ventures make semi-
annual payments to the counter party at variable rates based
on LIBOR, reset and compounded every three months, and in
return receive payments based on a fixed rate of 6.34%. The
effective LIBOR rate ranged from 3.25% to 3.375% during 1993
and was 3.375% at December 31, 1993. The counter party to
this agreement is a large multi-national financial
institution. The Company's proportionate share of the
carrying amount, representing accrued interest receivable, and
the fair value of the swap agreements are $277 and $1,281,
respectively. The fair value is based on quoted market prices
provided by the counter party to the swap.
In September 1993, the Company entered into a three year
deposit interest rate swap agreement, which effectively
converts a notional deposit balance of $75,000 from a variable
rate to a fixed rate. The Company makes semi-annual payments
to the counter party at effectively the LIBOR rate, reset
every six months, and in return receives payments based on a
fixed rate of 4.87%. The counter party to this agreement is
the same counter party to the Coso Joint Ventures. The
carrying amount is $286, representing accrued interest. The
fair value of the interest rate swap is currently negative in
the amount of $642 which is based on quoted market prices
provided by the counter party to the swap and assumes the
Company closes out the swap agreement prior to the stated
maturity.
4. PROPERTIES AND PLANTS
<TABLE>
Properties and plants comprise the following at December 31:
<CAPTION>
1993 1992
<S> <C> <C>
Project costs:
Power plants $246,219 $235,924
Well and resource development 161,137 144,595
Total operating facilities 407,356 380,519
Less accumulated depreciation and amortization (67,813) (51,054)
Net operating facilities 339,543 329,465
Wells and resource development in progress 939 916
Total project costs 340,482 330,381
Pacific Northwest geothermal exploration costs 41,539 25,882
Nevada and Utah properties 35,492 32,089
Yuma - construction in progress 41,461 1,294
Total $458,974 $389,646
</TABLE>
Operating Facilities
The Coso operating facilities comprise the Company's
proportionate share of the assets of three of its Joint
Ventures; Coso Finance Partners (Navy I Joint Venture), Coso
Energy Developers (BLM Joint Venture), and Coso Power
Developers (Navy II Joint Venture). With respect to the Coso
Project, distributions from its project accounts are made
semi-annually to each Coso Joint Venture partner for profit
sharing under a prescribed calculation subject to mutual
agreement by the partners and compliance with the Coso Joint
Ventures' financing documents. As of December 31, 1993,
payout had only been reached on Units 2 and 3 of the Navy I
power plant.
Navy I Plant
The Navy I plant consists of three turbines, of which one unit
commenced delivery of firm power in August 1987, and the
second and third units in December 1988. The 80NMW power
plant is located on land owned by and leased from the U.S.
Navy through to December 2009, with a 10 year extension at the
option of the Navy. Under terms of the Navy I Joint Venture,
profits and losses were allocated approximately 49% before
payout of Units 2 and 3 and approximately 46.4% thereafter to
the Company.
BLM Plant
The BLM plant consists of two turbines at one site (BLM East),
which commenced delivery of firm power in March and May,
1989, respectively, and one turbine at another site (BLM West)
which commenced delivery of firm power in August, 1989. The
BLM plant is situated on lands leased from the U.S. Bureau of
Land Management under a geothermal lease agreement that
extends until October 31, 2035. The lease may be extended to
2075 at the option of the BLM. Under the terms of the BLM
Joint Venture agreement, the Company's share of profits and
losses before and after payout is approximately 45% and 48%,
respectively. During 1990, the Company upgraded the cooling
tower and turbines to increase the plant's capacity to 80NMW
from the initial level of 70NMW.
Navy II Plant
The Navy II plant consists of three turbines, of which two
units commenced delivery of firm power in January 1990, and
the third in February 1990, respectively. The 80NMW power
plant is on the southern portion of the Navy lands. Under
terms of the Joint Venture, all profits, losses and capital
contributions for Navy II are divided equally by the two
partners.
Significant Customer
All of the Company's sales of electricity from the Coso
Project, which comprise approximately 94% of 1993 electricity
and steam revenues, are to Southern California Edison ("SCE")
and are under long-term power purchase contracts. Under the
terms of these contracts, SCE pays firm prices for the energy
portion of the contract. The energy payment escalates
pursuant to the contracts at an average rate of approximately
7.0% per year for the delivery of electricity for ten years,
commencing with the initial delivery of electricity at firm
power; thereafter, the energy payment adjusts to the actual
avoided energy cost experienced by SCE at that time. The
capacity payment, which initially represented approximately
25% of the Company's revenue, remains fixed during the entire
period of the contract. In addition, the Company is eligible
for bonus payments based on the amount by which the actual
output exceeds the contract capacity of each power plant.
Bonus payments aggregated $3,050, $3,257 and $2,635 in the
years ended December 31, 1993, 1992 and 1991.
The Company has three contracts for terms of 24, 30 and 20
years, expiring in 2011, 2019 and 2010, respectively.
Delivery of electricity by the Navy I Joint Venture, the BLM
Joint Venture, and Navy II Joint Venture commenced under those
contracts in 1987, 1989 and 1990, respectively.
See Note 13 for a description of litigation involving SCE.
Royalties
Royalties comprise the following for the years ended:
1993 1992 1991
Navy I, Unit I $1,556 $2,014 $1,787
Navy I, Units 2 and 3 2,924 2,628 1,160
BLM 1,868 1,268 1,033
Navy II 1,717 1,509 1,486
Other 209 291 39
Total $8,274 $7,710 $5,505
The amount of royalties paid by the Company to the U.S. Navy
to develop geothermal energy for Navy I, Unit 1 on the lands
owned by the Navy comprises (i) a fee payable during the term
of the contract based on the difference between the amounts
paid by the Navy to SCE for specified quantities of
electricity and the price as determined under the contract
(which currently approximates 71% of that paid by the Navy to
SCE), and (ii) $11,600 payable in December 2009. The $11,600
payment is secured by funds placed on deposit monthly, which
funds, plus accrued interest, will aggregate $11,600. The
monthly deposit is currently $23. As of December 31, 1993,
the balance of funds deposited approximated $1,283, which
amount is included in restricted cash and accrued liabilities.
Units 2 and 3 of Navy I and the Navy II power plants are on
Navy lands, on which the Navy receives a royalty based on
electric sales revenue at the initial rate of 4% escalating to
22% by the end of the contract in December 2019. The BLM is
paid a royalty of 10% of the value of steam produced by the
geothermal resource supplying the BLM Plant.
Pacific Northwest Geothermal Exploration Costs
In the Pacific Northwest, the Company has acquired leasehold
rights and has performed certain geological evaluations to
determine the resource potential of the underlying properties.
Recovery of those costs is ultimately dependent upon the
Company's ability to prove geothermal reserves and sell
geothermal steam, or to obtain financing, build power plants,
gain access to high voltage transmission lines, and sell the
resultant electricity at favorable prices or, sell its
leaseholds. In the opinion of management, the Company will be
able to realize its exploration costs through the generation
of electricity for sale.
Nevada and Utah Properties
On May 3, 1990, the Company entered into a definitive purchase
agreement with a subsidiary of Chevron Corporation ("Chevron")
for the acquisition of certain geothermal operations,
including interests in approximately 83,750 acres of
geothermal properties in Nevada and Utah, for an aggregate
purchase price of approximately $51,100. These property
interests consist largely of leasehold interests, including
properties leased from the BLM and from private landowners.
The property acquired from Chevron includes a 9MW power plant
at Desert Peak, Nevada ("Desert Peak"), and a 70% interest in
a steam field at Roosevelt Hot Springs, Utah ("Roosevelt Hot
Springs"). The facility at Desert Peak is currently selling
electricity to Sierra Pacific Power Company under a contract
that runs through 1995 and then may be extended on a year-to-
year basis as agreed by the parties. The price for
electricity under this contract is 6.5 cents per kWh,
comprising an energy payment of 2.0 cents per kWh (which is
adjustable pursuant to an inflation based index) and a
capacity payment of 4.5 cents per kWh. The Roosevelt Hot
Springs site has a contract to sell steam to a 25MW power
plant owned by Utah Power and Light Company ("UP&L") and to
dispose of the brine that is a by-product of the electricity
production process.
As part of the Nevada and Utah properties acquisition the
Company acquired leasehold interests in an aggregate of
approximately 20,000 acres at the Roosevelt Hot Springs site
in Utah and approximately 63,750 acres at four sites in
Nevada. The Roosevelt Hot Springs and Desert Peak properties
have been the subject of exploration and testing by Chevron
and its predecessors. Based on these tests and reports of
independent engineering companies, the Company believes that
there are significant geothermal resources available for
commercial development at these sites. Other tests conducted
by Chevron and its predecessors indicate that commercially
viable amounts of geothermal resources may underlie the other
Chevron properties.
The Company financed the acquisition of Roosevelt Hot Springs
through an equity offering, a $20,317 pre-sale of steam from
the Roosevelt Hot Springs field to the utility-owned power
plant located at the site, and seller financing. The
acquisition of Roosevelt Hot Springs and certain of the Nevada
properties closed on January 22, 1991 for an aggregate amount
of approximately $35,000. The remainder of the transaction
closed on March 28, 1991 and was financed with seller
financing and the proceeds of the sale of common stock to
Kiewit Energy Company ("Kiewit Energy"); see Note 12.
5. PROJECT LOANS
Project loans, which are non-recourse to the Company, comprise
the following at December 31:
<TABLE>
<CAPTION>
1993 1992
<S> <C> <C>
Project loans with fixed interest rates (weighted average
interest rates of 8.04% and 7.88% at December 31, 1993 and
1992, respectively) with scheduled repayments through December 2001 $246,880 $263,604
</TABLE>
The project loans are from Coso Funding Corp. ("Funding
Corp."). Funding Corp. is a single-purpose corporation formed
to issue notes for its own account and as an agent acting on
behalf of Navy I, BLM, and Navy II Joint Ventures,
collectively the "Coso Joint Ventures". Pursuant to separate
credit agreements executed between Funding Corp. and each Coso
Joint Venture on December 16, 1992, the proceeds from Funding
Corp.'s note offering were loaned to the Coso Joint Ventures.
The proceeds of $560,245 were used by the Coso Joint Ventures
to (i) purchase and retire project finance debt comprised of
the term loans and construction loans in the amount of
$424,500, (ii) fund contingency funds in the amount of
$68,400, (iii) fund debt service reserve funds in the amount
of $40,000, and (iv) finance $27,345 of capital expenditures
and transaction costs. The contingency fund and debt service
reserve fund were required by the project loan agreements.
The contingency fund represented the approximate maximum
amount, if any, which could theoretically have been payable by
the Coso Joint Ventures to third parties to discharge all
liens of record and other contract claims encumbering the Coso
Joint Ventures' plant at the time of the project loans (see
Note 13). The contingency fund was established in order to
obtain investment-grade ratings to facilitate the offer and
sale of the notes by Funding Corp., and such establishment did
not reflect the Coso Joint Ventures' view as to the merits or
likely disposition of such litigation or other contingencies.
On June 9, 1993, MPE and the Mission Power Group, subsidiaries
of SCECorp., and the Coso Joint Ventures reached a final
settlement of all of their outstanding disputes and claims
relating to the construction of the Coso Project. As a result
of the various payments and releases involved in such
settlement, the Coso Joint Ventures agreed to make a net
payment of $20,000 to MPE from the cash reserves of the Coso
Project contingency fund and MPE agreed to release its
mechanics' liens on the Coso Project. After making the
$20,000 payment, the remaining balance of the Coso Project
contingency fund (approximately $49,300) was used to increase
the Coso Project debt reserve fund from approximately $43,000
to its maximum fully-funded requirement of $67,900. The
remaining $24,400 balance of contingency fund was retained
within the Coso Project for future capital expenditures and
for Coso Project debt service payments. Since the Coso
Project debt service reserve is fully funded in advance, Coso
Project cash flows otherwise intended to fund the Coso Project
debt service reserve fund, subject to satisfaction of certain
covenants and conditions contained in the Coso Joint Ventures'
refinancing documents, may be available for distribution to
the Company in its proportionate share.
The loans are collateralized by, among other things, the power
plants, geothermal resource, debt service reserve funds,
contingency funds, pledge of contracts, and an assignment of
all such Coso Joint Ventures' revenues which will be applied
against the payment of obligations of each Coso Joint Venture,
including the project loans. Each Coso Joint Venture's assets
will secure only its own project loan, and will not be cross-
collateralized with assets pledged under other Coso Joint
Venture's credit agreements. The project loans are non-
recourse to any partner in the Coso Joint Ventures and Funding
Corp. shall solely look to such Coso Joint Venture's pledged
assets for satisfaction of such project loans. However, the
loans are cross-collateralized by the available cash flow of
each Coso Joint Venture. Each Coso Joint Venture after
satisfying a series of its own obligations has agreed to
advance support loans (to the extent of available cash flow
and, under certain conditions, its debt service reserve funds)
in the event revenues from the supporting Coso Joint Ventures
are insufficient to meet scheduled principal and interest on
their separate project loans.
The annual repayments of the project loans for the years
beginning January 1, 1994 and thereafter are as follows:
1994 $ 27,599
1995 32,109
1996 38,826
1997 41,729
1998 38,912
Thereafter 67,705
________
$246,880
Based on quoted market rates of the Funding Corp. notes, the
fair value of the project loan was approximately $260,276 at
December 31, 1993.
In connection with the aforementioned refinancing, the Company
entered into an agreement with Community Energy Alternatives
Incorporated ("CEA") for the Company to purchase at the close
of the Coso Project refinancing CEA's interest in the Coso
Project. Until the close of the Coso Project refinancing, CEA
had been a partner in a partnership structure organized by the
Company's Joint Venture Partner in the BLM project. The
Company purchased the CEA interest under certain terms and
conditions which are designed to provide the Company with a
17% per annum return on the CEA interest purchase price of
$9,800. The Company's 17% per annum return is secured in part
by a pledge and assignment to the Company of certain cash
flows to be received by the Company's Coso Project Joint
Venture Partner (and certain affiliates) from Coso Project
distributions. The Company has granted its Coso Project Joint
Venture Partner the right to purchase the CEA interest for a
price which will provide the Company a 17% per annum return
for the duration the Company owns the CEA interest.
6. SENIOR NOTES
The Senior Notes are due in March 1995, and bear interest
at the rate of 12% per annum, plus 10% of the Company's
share of the cash flow from the Coso Project, commencing
July 1, 1989 and terminating December 31, 1994. The Senior
Notes prohibit the payment of cash dividends unless the
Company has a net worth of at least $50,000 after payment
of such dividends, and dividends do not exceed 50% of
accumulated net income subsequent to December 31, 1987.
The Senior Notes also place restrictions on capital
expenditures not related to the Coso Project. The fair
value of the Senior Notes approximates the carrying value.
7. CONVERTIBLE SUBORDINATED DEBENTURES
In June of 1993, the Company issued $100,000 principal amount
of 5% convertible subordinated debentures ("debentures") due
July 31, 2000. The debentures are convertible into shares of
the Company's common stock at any time prior to redemption or
maturity at a conversion price of $22.50 per share, subject to
adjustment in certain circumstances. Interest on the
debentures is payable semi-annually in arrears on July 31 and
January 31 of each year, commencing on July 31, 1993. The
debentures are redeemable for cash at any time on or after
July 31, 1996 at the option of the Company. The redemption
prices commencing in the twelve month period beginning July
31, 1996 (expressed in percentages of the principal amount)
are 102%, 101%, 100% and 100% in 1996, 1997, 1998 and 1999,
respectively. The debentures are unsecured general
obligations of the Company and subordinated to all existing
and future senior indebtness of the Company. The fair value
of the debentures as of December 31, 1993 was approximately
$103,250, which is based on quoted market rates.
8. INCOME TAXES
On January 1, 1993, the Company adopted Statement of Financial
Accounting Standard No. 109 ("FAS 109"), "Accounting for
Income Taxes". The adoption of FAS 109 changes the Company's
method of accounting for income taxes from the deferred method
as required by Accounting Principles Board Opinion No. 11 to
an asset and liability approach. Under FAS 109, the net
excess deferred tax liability as of January 1, 1993 was
determined to be $4,100. This amount is reflected in 1993
income as the cumulative effect of a change in accounting
principle. It primarily represents the recognition of the
Company's tax credit carryforwards as a deferred tax asset.
There was no cash impact to the Company upon the required
adoption of FAS 109. Under FAS 109, the effective tax rate
increased to approximately 30% from 23.5% in 1992. This
increase was due to the Company's tax credit carryforward
being recognized as an asset and unavailable to reduce the
current period's effective tax rate for computing the
Company's provision for income taxes.
<TABLE>
Provision for income tax is comprised of the following at December 31:
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Currently payable:
State $ 3,300 $ 2,300 $ 2,134
Federal 7,686 4,444 261
$10,986 $ 6,744 $ 2,395
Deferred:
State 385 1,607 929
Federal 6,813 2,038 4,960
7,198 3,645 5,889
Total after benefit of extraordinary item 18,184 10,389 8,284
Tax benefit attributable to
extraordinary item ---- 1,533 ----
Total before benefit of extraordinary item $18,184 $11,922 $ 8,284
</TABLE>
The deferred expense is primarily temporary differences associated with
depreciation and amortization of certain assets.
<TABLE>
A reconciliation of the federal statutory tax rate to the effective tax rate
applicable to income before provision for income taxes follows:
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Federal statutory rate 35.00% 34.00% 34.00%
Percentage depletion in excess of cost depletion (6.7) (6.81) (6.89)
Investment and energy tax credits (4.62) (10.52) (10.93)
State taxes, net of federal tax effect 3.90 5.83 6.32
Cumulative effect of change in federal tax rate 1.90 --- ---
Other .20 1.00 1.26
29.68% 23.50% 23.76%
</TABLE>
Deferred tax liabilities (assets) are comprised of the following at December 31:
1993
Depreciation and amortization, net $111,117
Other 1,733
_______
112,850
Deferred income (2,415)
Loss carryforwards (39,529)
Energy and investment tax credits (40,106)
Alternative minimum tax credits (12,018)
Other (472)
_______
(94,540)
_______
Net deferred taxes $ 18,310
In 1992, the significant components of the deferred tax
liability were timing differences in the computation of
depreciation and amortization of the power plants and
exploration and development costs for financial reporting
purposes versus income tax purposes.
As of December 31, 1993, the Company has an unused net
operating loss (NOL) carryover of approximately $113,000 for
regular federal tax return purposes which expires primarily
between 2001 and 2007. In addition, the Company has unused
investment and geothermal energy tax credit carryforwards of
approximately $40,106 expiring between 2002 and 2008. The
Company also has approximately $12,018 of alternative minimum
tax credit carryforwards which have no expiration date.
9. COMMITMENTS
The Company's former office space lease, which requires annual
rental of $660 through April 1994, has been partially sublet
at annual rentals of $261 and remaining future rental costs
were previously provided for in a restructuring charge. The
Company also leases an aircraft under a lease that expires on
August 1, 1995, at an annual rental of approximately $464.
The aircraft has been subleased at an annual rental of
approximately $300. Rental expense for the aircraft,
vehicles, geothermal leases, and other equipment leases for
the years ended December 31, 1993, 1992 and 1991 was
approximately $1,143, $1,018 and $986 respectively.
Total projected lease commitments (net of sublease contracts)
at December 31, 1993, are as follows:
Year Ended
December 31, Amount
1994 $318
1995 186
1996 8
Total $512
10. PREFERRED STOCK
Series A:
On December 1, 1988, the Company distributed a dividend of one
preferred share purchase right ("right") for each outstanding
share of common stock. The rights are not exercisable until
ten days after a person or group acquires or has the right to
acquire, beneficial ownership of 20% or more of the Company's
common stock or announces a tender or exchange offer for 30%
or more of the Company's common stock. Each right entitles
the holder to purchase one one-hundredth of a share of Series
A junior preferred stock for $52. The rights may be redeemed
by the Board of Directors up to ten days after an event
triggering the distribution of certificates for the rights.
The rights plan was amended in February 1991 so that the
agreement with Kiewit Energy (see Note 12) would not trigger
the exercise of the rights. The rights will expire, unless
previously redeemed or exercised, on November 30, 1998. The
rights are automatically attached to, and trade with, each
share of common stock.
Series B:
On November 15, 1990, the Company sold 357.5 shares of
convertible preferred stock, Series B at $14 per share. Each
share of the convertible preferred stock was convertible into
two shares of common stock, and had a dividend rate of 15%
through November 15, 1992, 10% from November 16, 1992 to
November 15, 1994 and 5% from November 16, 1994 to November
15, 1996. The dividends were payable semi-annually in
convertible preferred stock, Series B.
On November 15, 1992, the Company called the preferred stock
for conversion into common stock. Each Series B preferred
stock was converted into two shares of common stock;
accordingly, the Company issued 954.9 shares of common stock.
Series C:
On November 19, 1991, the Company sold one thousand shares of
convertible preferred stock, Series C at $50,000 per share to
Kiewit Energy, in a private placement. Each share of the
Series C preferred stock is convertible at any time at $18.375
per common share into 2,721 shares of common stock subject to
customary adjustments. The Series C preferred stock has a
dividend rate of 8.125%, commencing March 15, 1992 through
conversion date or December 15, 2003. The dividends, which
are cumulative, are payable quarterly in convertible preferred
stock, Series C, through March 15, 1995 and in cash on
subsequent dividend dates.
The Company is obligated to redeem 20% of the outstanding
preferred stock, Series C each December 15, commencing 1999
through 2003 at a price per share equal to $50,000, plus
accrued and unpaid dividends.
At any time after December 15, 1994, upon 20 days written
notice, the Company may redeem all, or any portion consisting
of at least $5,000, of the preferred stock, Series C, then
outstanding, provided that the Company's common stock has
traded at or above 150% of the then effective conversion
price, for any 20 trading days out of 30 consecutive trading
days ending not more than five trading days prior to notice of
redemption.
The Company may also exchange the preferred stock, Series C,
in whole or part on any dividend date commencing December 15,
1994, for 9.5% convertible subordinated debentures of the
Company due 2003.
Each share of preferred stock, Series C shall be entitled to
the number of votes equal to $50,000 per share divided by the
then effective conversion price. If cash dividends are in
arrears six consecutive quarters, Kiewit Energy shall have the
exclusive right, voting separately as a class, to elect two
directors of the Company.
No cash dividends shall be paid or declared on the Company's
common stock unless all accumulated dividends on the Series C
preferred stock have been paid.
11. STOCK OPTIONS AND WARRANTS
The Company has issued various stock options and warrants. As
of December 31, 1993, a total of 8,953 shares are reserved for
stock options, of which 8,514 shares have been granted and
remain outstanding at prices of $3.00 to $19.00 per share.
Stock Options
The Company has stock option plans under which shares were
reserved for grant as incentive or non-qualified stock
options, as determined by the Board of Directors. As of
December 31, 1993, the total options granted for the non-1986
plan and the 1986 plan are 5,778 and 6,354, respectively. The
plans allow options to be granted at 85% of their fair market
value at the date of grant. Generally, options are issued at
100% of fair market value at the date of grant. Options
granted under the 1986 Plan become exercisable over a period
of three to five years and expire if not exercised within ten
years from the date of grant or, in some instances a lesser
term. Prior to the 1986 Plan, the Company granted 256 options
at fair market value at date of grant which had terms of ten
years and were exercisable at date of grant. In addition, the
Company had issued approximately 138 options to consultants on
terms similar to those issued under the 1986 Plan. The non-
1986 plan options are primarily options granted to Kiewit
Energy; see Note 12.
<TABLE>
Transactions in Stock Options
OPTIONS OUTSTANDING
<CAPTION>
Shares Available for
Grant Under 1986 Option Price
Option Plan Shares Per Share Total
<S> <C> <C> <C> <C>
Balance January 1, 1991 72 3,361 $3.00 - $13.096 $ 12,658
Options granted (368) 8,268<F1> $8.063 - $14.875 89,193
Options terminated 304 (331) $3.00 - $9.708 (3,065)
Options exercised --- (2,328)<F1> $3.00 - $9.00 (15,116)
Additional shares reserved under 1986
Option Plan 1,230 --- --- ---
Balance, December 31, 1991 1,238 8,970<F1> $3.00 - $14.875 83,670
Options granted (551) 751 $11.90 - $15.938 11,262
Options terminated 129 (780) $3.00 - $11.625 (7,839)
Options exercised --- (1,544) $3.00 - $11.625 (7,072)
Balance December 31, 1992 816 7,397<F1> $3.00 - $15.938 80,021
Options granted (1,396) 1,396 $17.75 - $19.00 26,209
Options terminated 19 (20) $3.00 - $14.875 (114)
Options exercised --- (259) $3.00 - $14.875 (1,185)
Additional shares reserved under 1986
Option Plan 1,000 --- --- ---
Balance December 31, 1993 439 8,514<F1> $3.00 - $19.00 $104,931
Options which became exercisable during:
Year ended December 31, 1993 592 $3.00 - $19.00 $ 10,180
Year ended December 31, 1992 333 $3.00 - $15.938 $ 3,693
Year ended December 31, 1991 7,767<F1> $3.00 - $14.88 $ 79,890
Options exercisable at:
December 31, 1993 7,026<F1> $3.00 - $19.00 $ 78,644
December 31, 1992 6,708<F1> $3.00 - $15.938 $ 69,739
December 31, 1991 8,070<F1> $3.00 - $14.88 $ 73,481
<FN>
<F1> *Includes Kiewit Energy options. See Note 12.
</TABLE>
Warrants
The Company has granted warrants in connection with various financing
activities to purchase shares of common stock
as follows:
<TABLE>
<CAPTION>
WARRANTS OUTSTANDING
Warrant Shares Price per Share Total
<S> <C> <C> <C>
Balance January 1, 1991 2,549 $2.04 - $6.67 $ 6,804
Warrants exercised (660) $2.04 - $6.67 (2,951)
Balance, December 31, 1991 1,889 $2.04 3,853
Warrants exercised (612) $2.04 (1,247)
Warrants repurchased (1,277) $2.04 (2,606)
Balance December 31, 1992 --- $ ---
</TABLE>
On October 13, 1992, the Company repurchased, and cancelled, certain
warrants exercisable for 1,025 shares of unregistered common stock at
$2.04 per share, for a purchase price of $9.16 per share or $9,389 in
aggregate. Separately, Kiewit Energy simultaneously purchased and
exercised other warrants to purchase 600 shares of unregistered common
stock at $2.04 per share, providing the Company with proceeds of
$1,224.
On October 27, 1992, the Company repurchased, and cancelled, certain
warrants exercisable for 250 shares of unregistered common stock at
$2.04 per share, for a purchase price of $9.316 per share or $2,329
in aggregate.
12. COMMON STOCK SALES & RELATED OPTIONS
In January 1991, the Company sold 2,505 shares of unregistered common
stock at $6.75 per share for an aggregate total of $16,909. The funds
were used to repay a portion of the seller financing related to the
Company's acquisition of Chevron's interest in Roosevelt Hot Springs,
Utah.
The Company and Kiewit Energy signed a Stock Purchase Agreement and
related agreements, dated as of February 18, 1991. Kiewit Energy is
a subsidiary of Peter Kiewit Sons', Inc. of Omaha, Nebraska, a large
construction, mining, and telecommunications company with diversified
operations. Under the terms of the agreements, Kiewit Energy
purchased 4,000 shares of common stock at $7.25 per share and received
options to buy 3,000 shares at a price of $9 per share exercisable
over three years and an additional 3,000 shares at a price of $12 per
share exercisable over five years (subject to customary adjustments).
In connection with this initial stock purchase, the Company and Kiewit
Energy also entered into certain other agreements pursuant to which
(i) Kiewit Energy and its affiliates agreed not to acquire more than
34% of the outstanding common stock (the "Standstill Percentage") for
a five-year period, (ii) Kiewit Energy became entitled to nominate at
least three of the Company's directors, and (iii) the Company and
Kiewit Energy agreed to use their best efforts to negotiate and
execute a joint venture agreement relating to the development of
certain geothermal properties in Nevada and Utah.
On June 19, 1991, the board approved a number of amendments to the
Stock Purchase Agreement and the related agreements. Pursuant to
those amendments, the Company reacquired from Kiewit Energy the rights
to develop the Nevada and Utah properties, and Kiewit Energy agreed
to exercise options to acquire 1,500 shares of common stock at $9.00
per share, providing the Company with $13,500 in cash. The Company
also extended the term of the $9.00 and $12.00 options to seven years;
modified certain of the other terms of these options; granted to
Kiewit Energy an option to acquire an additional 1,000 shares of the
outstanding common stock at $11.625 per share (closing price for the
shares on the American Stock Exchange on June 18, 1991) for a ten year
term; and increased the Standstill Percentage from 34% to 49%.
On November 19, 1991, the Board approved the issuance by the Company
to Kiewit Energy of one thousand shares of Series C preferred stock
for $50,000, as described in Note 10 above. In connection with the
sale of the Series C preferred stock to Kiewit Energy, the Standstill
Agreement was amended so that the 49% Standstill Percentage
restriction would apply to voting stock rather than just common stock.
13. LITIGATION
Settlement of Contractor Claims
In June 1990, Mission Power Engineering Company ("MPE"), a subsidiary
of SCECorp. and the general contractor for eight of the nine
facilities at the Coso Project recorded mechanic's liens (the "Liens")
against two of the Coso Projects and filed suit to pursue claims for
amounts allegedly due from the Coso Joint Ventures in connection with
the turnkey contracts for the design and construction on eight of the
units. In July 1990, MPE, the Coso Joint Venture Partners and the
Company agreed to enter settlement discussions during which period the
suit was suspended. In January 1991, MPE terminated settlement
discussions and refiled its suit in the amount of approximately
$70,900 in contract claims. The Coso Joint Ventures counterclaimed
on January 10, 1991, for performance and equipment related and other
damages arising under the turnkey contracts.
On June 9, 1993, MPE and the Mission Power Group, subsidiaries of
SCECorp, and the Coso Joint Ventures and the Company announced that
the companies had reached a final settlement of all of their
outstanding disputes relating to the construction of and the filing
of mechanics' liens against the Coso Project.
Under the settlement agreement, MPE agreed to dismiss with prejudice
its $70,900 breach of contract suit against the Coso Joint Ventures
and the Coso Joint Ventures agreed to dismiss with prejudice their
counterclaims against MPE and related parties. As a result of the
various payments and releases involved in such settlement, the Coso
Joint Ventures agreed to make a net payment of $20,000 to MPE from the
cash reserves of the Coso Project Contingency Fund and MPE agreed to
release its mechanics' liens on the Coso Project.
Settlement of Transmission Line Disputes
In September 1990, the California Public Utilities Commission ("CPUC")
issued a decision which would fix at approximately $10,500 the Coso
Joint Ventures' maximum exposure for the cost of the construction of
a new 220kV electric transmission line ("Line") on the SCE
transmission system. The Coso Joint Ventures appealed the decision
of the CPUC to the Federal district court and intended to petition the
CPUC to reconsider its decision on the grounds that such Line is not
necessary. In a related proceeding involving the cost allocation for
existing and ancillary interconnection facilities, the CPUC ruled that
the Coso Joint Ventures' share would be approximately $7,000. The
Coso Joint Ventures appeal of such decision to the California Supreme
Court was denied in February 1993. In addition, SCE alleged certain
line losses that SCE deemed applicable to the existing 115kV line
utilized by two of the Coso Joint Ventures and deducted amounts from
revenues payable under the power purchase contracts. The Coso Joint
Ventures dispute SCE's allegations, methodology and alleged ability
to deduct amounts under the interconnection contracts and filed a
complaint alleging breach of contract in the California State Court.
On May 3, 1993, SCE and the Coso Joint Ventures agreed to settle the
transmission line loss contract dispute and certain related
interconnection disputes involving the Coso Project under a separate
agreement whereby, among other things, the parties made certain cash
payments to each other and agreed to certain interconnection cost and
historical line loss allocations and to the release to the Coso Joint
Ventures of certain funds previously deducted from project revenues
and held in escrow. The parties also agreed to jointly pursue
appropriate rate treatment by the CPUC of certain SCE financed
interconnection costs, including the one remaining cost allocation
issue between them in the amount of $5,900. As a result of the
various payments, allocations and releases involved in such partial
settlement, SCE released $15,500 of Coso Project funds (the Company's
share was approximately $7,800) held in escrow in respect of
interconnection costs (transmission line deposit) and the Partners of
Coso Joint Ventures' posted an irrevocable letter of credit to support
their contingent obligation of $5,900 on the cost allocation matter
to be jointly pursued with SCE at the CPUC.
Settlement of Anti-Trust Lawsuit
On January 31, 1991, the Company filed an antitrust lawsuit in San
Francisco Federal Court against SCECorp., its subsidiaries, (MPE,
Mission Power Group and SCE), Kidder-Peabody & Co., and others
alleging violations of the federal antitrust laws, unfair competition
and tortious interference. This lawsuit was settled in conjunction
with the transmission line disputes.
Settlement with Joint Venture Partner
The Company has served as managing partner, project manager and field
operator for the Coso Project since its inception. It has been plant
operator for the facilities since August 1988. In April 1990, the
Company's principal Coso Joint Venture partner (the "J.V. Partner")
served the Company and certain of the Company's subsidiaries with a
demand for arbitration arising out of disagreements concerning
primarily the operating budgets and the allocation to the Coso Joint
Ventures of certain expenses incurred by the Company.
On March 19, 1991, the Company and its J.V. Partner executed a
settlement agreement which resolved all their outstanding disputes.
The terms of the settlement provide that if the Coso Project performs
at capacity level in the future so that certain formula-based
contingencies related to the productivity of the power plants are
satisfied in any of the following eight years, then, out of the excess
cash flow generated from such performance levels, up to $1,400 may be
paid in each such year to the J.V. Partner by the Company. During
1992, the Company purchased the J.V. Partner's contingent payment for
$5,000; which will be amortized over the remaining seven years of the
agreement.
In return for the original settlement, the J.V. Partner agreed to the
conversion of all prior advances made by the Company on behalf of the
partnership into a Joint Venture note payable to the Company due on
or before March 19, 1999. The note bore interest at an adjustable
rate tied to LIBOR and was subordinated to the prior payment in full
of all the senior bank debt on the project as well as to the foregoing
contingent payments to the J.V. Partner. On December 16, 1992 the
Coso Joint Ventures paid $5,133 of their note payable plus accrued
interest to the Company. A new promissory note was then signed on
December 16, 1992 for the remaining principal balance. This note
bears a fixed interest rate of 12.5% and is payable on or before March
19, 2002. This note continues to be subordinated to the senior
project loan on the project. The fair value of this note approximates
the carrying value.
14. RELATED PARTY TRANSACTIONS
The Company charged and recognized a management fee and interest on
advances to its Coso Joint Ventures, which aggregated approximately
$5,354, $4,246 and $5,664 in the years ended December 31, 1993,
1992 and 1991.
15. EXTRAORDINARY ITEM
The refinancing of the Coso Joint Ventures' project financing debt in
1992 resulted in an extraordinary item in the amount of $4,991, after
the tax effect of $1,533. The extraordinary item represents the
unamortized portion of the deferred financing costs and related
repayment costs associated with the original Coso Joint Ventures'
project financing debt.
16. SUBSEQUENT EVENT
The Company is currently in the process of arranging a proposed
offering of $400,000 Senior Discount Notes ("Notes"). The interest
rate will be between approximately 9% and 10%, with cash interest
payment commencing in 1997. The Notes will be senior unsecured
obligations of the Company. The Company intends to use the proceeds
from the offering to: (i) fund equity commitments in, and the
construction costs of, geothermal power projects presently planned in
the Philippines and Indonesia, (ii) fund equity investments in, and
loans to, other potential international and domestic private power
projects and related facilities, (iii) for corporate or project
acquisitions permitted under the indenture, and (iv) for general
corporate purposes.
17. QUARTERLY FINANCIAL DATA (UNAUDITED)
Following is a summary of the Company's quarterly results of
operations for the years ended December 31, 1993 and December 31,
1992.
<TABLE>
<CAPTION>
Three Months Ended *
March 31 June 30, September 30, December 31,
1993 1993 1993 1993
<S> <C> <C> <C> <C>
Revenue:
Sales of electricity and steam $ 27,617 $ 31,996 $ 41,433 $ 31,013
Other income 3,544 3,926 4,824 4,900
Total revenue 31,161 35,922 46,257 35,913
Total costs and expenses 20,314 21,833 22,087 23,761
Income before provision for income taxes
and change in accounting principle 10,847 14,089 24,170 12,152
Provision for income taxes 3,363 3,439 7,493 3,889
Net income before change in
accounting principle 7,484 10,650 16,677 8,263
Cumulative effect of change in accounting
principle 4,100 --- --- ---
Net income 11,584 10,650 16,677 8,263
Preferred dividends 1,107 1,143 1,179 1,201
Net income attributable to common shares $ 10,477 $ 9,507 $ 15,498 $ 7,062
Net income per share before change in
accounting principle $ .16 $ .25 $ .41 $ .18
Cumulative effect of change in accounting
principle .11 --- --- ---
Net income per share $ .27 $ .25 $ .41 $ .18
</TABLE>
<TABLE>
<CAPTION>
Three Months Ended*
March 31, June 30, September 30, December 31,
1992 1992 1992 1992
<S> <C> <C> <C> <C>
Revenue:
Sales of electricity and steam $ 24,147 $ 28,173 $ 37,977 $ 27,045
Other income 1,995 2,609 3,160 2,423
Total revenue 26,142 30,782 41,137 29,468
Total costs and expenses 18,541 18,779 20,583 18,894
Income before provisions for income taxes and
extraordinary item 7,601 12,003 20,554 10,574
Provision for income taxes 1,806 2,852 4,884 2,380
Net income before extraordinary item 5,795 9,151 15,670 8,194
Extraordinary item --- --- --- 4,991
Net income 5,795 9,151 15,670 3,203
Preferred dividends 1,020 1,056 1,089 1,110
Net income attributable to common shares $ 4,775 $ 8,095 $ 14,581 $ 2,093
Net income per share before
extraordinary item $ .13 $ .22 $ .39 $ .19
Extraordinary item --- --- --- (.13)
Net income per share $ .13 $ .22 $ .39 $ .06
</TABLE>
*The Company's operations are seasonal in nature with a disproportionate
percentage of income earned in the second and third quarters.
Independent Auditors' Report
Board of Directors and Shareholders
California Energy Company, Inc.
Omaha, Nebraska
We have audited the accompanying consolidated balance sheets
of California Energy Company, Inc. and subsidiaries as of
December 31, 1993 and 1992, and the related consolidated
statements of operations, stockholders' equity and cash flows for
each of the three years in the period ended December 31, 1993.
These financial statements are the responsibility of the
Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of
California Energy Company, Inc. and subsidiaries at December 31,
1993 and 1992 and the results of their operations and their cash
flows for each of the three years in the period ended December
31, 1993, in conformity with generally accepted accounting
principles.
As discussed in Note 8, the consolidated financial statements
give effect to the Company's adoption, effective January 1, 1993,
of Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes".
Deloitte & Touche
Omaha, Nebraska
February 24, 1994
California Energy Company, Inc.
Subsidiaries
PARENT COMPANY
California Energy Company, Inc.
SUBSIDIARIES
Coso-Related Companies/Partnerships
Coso Hotsprings Intermountain Power, Inc.
Coso Energy Developers
China Lake Operating Co.
Coso Finance Partners
Coso Technology Corporation
Coso Power Developers
Coso Funding Corp.
Coso Transmission Line Partners
China Lake Geothermal Management Co.
Coso Finance Partners II
California Energy General Corporation
CEGC - Mojave Partnership
China Lake Plant Services, Inc.
Coso Land Company
China Lake Joint Venture
Coso Geothermal Company
Coso Hotsprings Overland Power, Inc.
Operating Companies/Partnerships
CE Geothermal Inc.
Western States Geothermal Company
Intermountain Geothermal Company
CE CIS-FSU, Inc.
Russian-American Science, Inc.
California Energy Development Corporation
California Energy Yuma Corporation
Yuma Cogeneration Associates
Rose Valley Properties, Inc.
The Ben Holt Co.
Development (Holding) Companies
CE Exploration Company
CE Newberry, Inc.
CE Humboldt, Inc.
Beowawe Geothermal, Inc.
American Pacific Finance Company
International Companies
CE Cebu Geothermal Power Company, Inc.
CE International Ltd.
CE Indonesia Ltd.
CE Luzon Geothermal Power Company, Inc.
CE Philippines Ltd.
Himpurna California Energy Ltd.
Ormat Cebu Ltd.
Exhibit 23.0
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statements No.
33-41152 and No. 33-52147 on Form S-8 and Registration Statement No. 33-
51363 on Form S-3 of California Energy Company, Inc. of our reports dated
February 24, 1994, appearing in and incorporated by reference in the Annual
Report on Form 10-K of California Energy Company, Inc. for the year ended
December 31, 1993.
DELOITTE & TOUCHE
/s/ Deloitte & Touche
Omaha, Nebraska
March 29, 1994
POWER OF ATTORNEY
The undersigned, a member of the Board of Directors of California
Energy Company, Inc., a Delaware corporation (the "Company"), hereby
constitutes and appoints Steven A. McArthur, as his/her true and lawful
attorney-in-fact and agent, with full power of substitution and
resubstitution, for and in his/her stead, in any and all capacities, to
sign on his/her behalf the Form 10-K Annual Report of the Company filed for
the fiscal year ending December 31, 1993 and to execute any amendments
thereto, and to file the same, with all exhibits thereto, and all other
documents in connection therewith, with the Securities and Exchange
Commission and applicable stock exchanges, with the full power and
authority to do and perform each and every act and thing necessary or
advisable to all intents and purposes as he/she might or could do in
person, hereby ratifying and confirming all that said attorney-in-fact and
agent, or his/her substitute or substitutes, may lawfully do or cause to be
done by virtue hereof.
DATE: March 31, 1994
/s/ Richard R. Jaros /s/ Everett B. Laybourne
Richard R. Jaros Everett B. Laybourne
/s/ Edgar D. Aronson /s/ Adm. Daniel J. Murphy
Edgar D. Aronson Adm. Daniel J. Murphy
/s/ Judith E. Ayres /s/ Herbert L. Oakes, Jr.
Judith E. Ayres Herbert L. Oakes, Jr.
/s/ Harvey F. Brush /s/ Walter Scott, Jr.
Harvey F. Brush Walter Scott, Jr.
/s/ James Q. Crowe /s/ Barton W. Shackelford
James Q. Crowe Barton W. Shackelford
/s/ Richard K. Davidson /s/ David L. Sokol
Richard K. Davidson David L. Sokol
/s/ Ben Holt /s/ David E. Wit
Ben Holt David E. Wit
Exhibit 27
Financial Data Schedule
Item 601(c) of Regulation S-K Commercial
and Industrial Companies Article 5 of Regulation S-X
(dollars in thousands, except per share amounts)
<TABLE>
<CAPTION>
December 31,
Item Number Item Description 1993
- - ------------------- ---------------------------------------------------------------------------- ------------
<S> <C> <C>
5-02(1) cash and cash items......................................................... 127,756
5-02(1) cash and cash items-joint ventures.......................................... 14,943
5-02(1) cash and cash items-restricted.............................................. 48,105
5-02(2) marketable securities....................................................... N/A
5-02(3)(a)(1) notes and accounts receivable-trade......................................... 21,658
5-02(4) allowances for doubtful accounts............................................ N/A
5-02(6) inventory................................................................... N/A
5-02(9) total current assets........................................................ N/A
5-02(13) property-power plant, net................................................... 458,974
5-02(13) property-equipment, net..................................................... 4,540
5-02(14) accumulated depreciation-plant.............................................. 67,813
5-02(14) accumulated depreciation equipment.......................................... 4,773
5-02(18) total assets................................................................ 715,984
5-02(21) total current liabilities................................................... N/A
5-02(22) bonds and mortgages and similar debt-senior notes........................... 35,730
5-02(22) bonds and mortgages and similar debt-convertible debentures................. 100,000
5-02(28) preferred stock-mandatory redemption........................................ 58,800
5-02(29) preferred stock-no mandatory redemption..................................... N/A
5-02(30) common stock................................................................ 2,404
5-02(31) other stockholders' equity-additional paid-in capital....................... 100,965
5-02(31) other stockholders' equity-retained earnings................................ 111,031
5-02(32) total liabilities and stockholders' equity.................................. 715,984
5-03(b)1(a) net sales of tangible products.............................................. 132,059
5-03(b)1 total revenues.............................................................. 149,253
5-03(b)2(a) cost of tangible goods sold................................................. N/A
5-03(b)2 total costs and expenses applicable to sales and revenues-plant operations.. 25,362
5-03(b)3 other costs and expenses-general and administration......................... 13,158
5-03(b)3 other costs-royalties....................................................... 8,274
5-03(b)5 provision for doubtful accounts and notes................................... N/A
5-03(b)(8) interest and amortization of debt discount.................................. 30,205
5-03(b)(8) interest and amortization-capitalized....................................... (6,816)
5-03(b)(10) income before taxes and other items......................................... 61,258
5-03(b)(11) income tax expense.......................................................... 18,184
5-03(b)(14) income continuing operations................................................ 43,074
5-03(b)(15) discontinued operations..................................................... N/A
5-03(b)(17) extra ordinary items........................................................ N/A
5-03(b)(18) cumulative effect-changes in accounting principle........................... 4,100
5-03(b)(19) net income.................................................................. 47,174
5-03(b)(20) earnings per share primary.................................................. 1.11
5-03(b)(20) earnings per share fully diluted............................................ 1.11
</TABLE>
